DSHW-2024-008553

STATE OF UTAH
DEPARTMENT OF ENVIRONMENTAL QUALITY
DIVISION OF WASTE MANAGEMENT AND RADIATION CONTROL

RESPONSE TO COMMENTS

Utah Administrative Code R315-301, 302, 303, 304, 305, 307,
308, 310, 311, 314, 315, 316, 317, 318, 321, and 322

October 7, 2024

On July 11, 2024, the Waste Management and Radiation Control Board proceeded with formal
rulemaking and public comment on two new rules. Utah Administrative Code R315-321, Class VII
Exploration and Production Waste Landfill Requirements, provides administrative requirements for
the regulation of Class VII landfills for the disposal of waste generated from the exploration,
development, and production of oil, gas, or geothermal energy. Utah Administrative Code R315-322,
Solid Waste Surface Impoundment Requirements, provides administrative requirements for the
regulation of waste liquids in surface impoundments.

The new rules, and amendments to 14 existing rules found in Utah Admin. Code R315 was open for
public comment from August 1, 2024, through September 3, 2024. This document contains responses
to comments received.

Contents
1. Director Discretion ......................................................................................................................... 5
2. Class VII Landfill Comments ......................................................................................................... 5
2.1 Leachate ................................................................................................................................ 5
2.2 Liner Requirements ............................................................................................................... 6
2.2.1 Rule Reference to Liners ................................................................................................... 6
2.2.2 Liners (R N Industries, Inc. (RNI)) ................................................................................... 7
2.2.3 Liners (Integrated Water Management, LLC (IWM)) ...................................................... 7
2.2.4 Liners (IWM) .................................................................................................................... 9
2.2.5 Liners (IWM) .................................................................................................................. 10
2.2.6 Liners (IWM) .................................................................................................................. 11
2.2.7 Liners (IWM) .................................................................................................................. 13
2.2.8 Liners (IWM) .................................................................................................................. 15
2.2.9 Liners (IWM) .................................................................................................................. 16
2.2.10 Liners (IWM) .............................................................................................................. 18
2.2.11 Liners (IWM) .............................................................................................................. 19
2.2.12 Liners (IWM) .............................................................................................................. 20
2.2.13 Liners (IWM) .............................................................................................................. 21
2.2.14 Liners (IWM) .............................................................................................................. 22
2.2.15 Liners – Board Authority to Pass Rules (RNI) ........................................................... 22
2.2.16 Liners – Board Authority to Pass Rules (RNI) ........................................................... 23
2.2.17 Liners – DOGM Requirements ................................................................................... 23
2.2.18 Liners – Landfill vs. Surface Impoundment ............................................................... 23
2.3 Extreme Depth to Groundwater .......................................................................................... 24
2.4 Engineering Reports and Plans ........................................................................................... 24
2.5 Location Standards - Groundwater...................................................................................... 24
2.6 Transfer of Waste to Surface Impoundments ...................................................................... 25
2.7 Unlevel Playing Field .......................................................................................................... 25
2.8 Arbitrary and Capricious Agency Action. ........................................................................... 26
3. Solid Waste Surface Impoundment Comments ............................................................................ 27
3.1 Applicability Reference Needed in Rule R315-303 ............................................................ 27
3.2 Groundwater Monitoring and Leak Detection .................................................................... 27
3.2.1 Alternatives and Waivers for Groundwater Monitoring ................................................. 27
3.2.2 Leak Detection Waiver at Unloading Structures............................................................. 28
3.2.3 Electrically Conductive Geofabric .................................................................................. 28
3.2.4 Liner Integrity Surveys ................................................................................................... 28
3.2.5 Combined Leak Detection and Groundwater Monitoring ............................................... 29
3.2.6 Maximum Allowable Leak Rates .................................................................................... 29
3.2.7 Unsealed Liners ............................................................................................................... 29
3.3 Hydrocarbon Accumulation on Surface Impoundments ..................................................... 30
3.4 Overspray Control ............................................................................................................... 30
3.5 Protection of Waterfowl and Other Wildlife Receptors ...................................................... 31
3.6 Size Limits ........................................................................................................................... 31
3.7 Surface Impoundment Liner Options .................................................................................. 32
3.8 Stormwater Retention Ponds ............................................................................................... 33
4. Groundwater Protection – Landfills or Surface Impoundments................................................... 34
4.1 Natural Impermeable Barrier............................................................................................... 34
5. Financial Assurance ..................................................................................................................... 35
5.1 Certificates of Deposit ......................................................................................................... 35
6. General ......................................................................................................................................... 35
6.1 Flocculation and Dispersion of Clay ................................................................................... 35
6.2 Location Standards .............................................................................................................. 36
6.2.1 Location Standards Citation in R315-322 ....................................................................... 36
6.2.2 Location Standards Exemptions ...................................................................................... 36
7. Waste Characterization................................................................................................................. 36
7.1 How to Make a Waste Determination ................................................................................. 36
7.2 Hazardous Waste from a Very Small Quantity Generator (VSQG).................................... 37
7.2.1 Disposal from Multiple VSQGs ...................................................................................... 37
7.2.2 VSQG Waste Training .................................................................................................... 37
7.2.3 VSQG Waste Determination ........................................................................................... 38
7.2.4 VSQG Waste Not Incidental to E&P .............................................................................. 38
8. General Questions ........................................................................................................................ 39
8.1 EPA vs DWMRC Standards ............................................................................................... 39
8.2 Initial Permit ........................................................................................................................ 40
8.3 Landfarm Reclamation ........................................................................................................ 40
8.4 Removal of Waste from a Landfill ...................................................................................... 41
8.5 Soil Testing – Background .................................................................................................. 41
8.6 Soil Testing – Closure ......................................................................................................... 41
8.7 Skim Ponds .......................................................................................................................... 41
8.7.1 De minimis Hydrocarbon Accumulation ........................................................................ 41
8.7.2 Netting ............................................................................................................................. 42
8.8 Oil Pits Should Have Liners ................................................................................................ 42
Attachment: EPA 2019 Report
Attachment: 2019 General Legislative Session House Bill 310
Attachment: AGO Memo-Liners

1. Director Discretion
Several comments addressed the Director's authority. Generally, the comments requested
specification through articulable standards when the Director may approve an alternative,
exempt or waive a requirement, or when the Director may require a more stringent
standard. Phrases from the rules that led to this comment include “as determined by the
Director,” “unless determined unnecessary by the Director,” and “if the Director
determines that the exemption will cause no adverse impact.”
Response: In each case that allows for Director discretion, a standard is set in the rules.
Administrative rules cannot account for every possible scenario. The discretionary
options provided in the rules allow the Director to consider circumstances that are
unforeseen or for which there is not an explicit definition or framework, and provides
flexibility for the Director to determine how to protect human health and the environment
in any given situation. This might include but is not limited to proposed alternative waste
handling or treatment practices, alternative designs, technologies, and infrastructure.
In cases where the rule allows Director discretion, an applicant normally provides the
justification for the alternative requested and is responsible to ensure that all required
performance standards are achieved. The justification should be compelling and may
require the applicant to conduct trials to demonstrate the validity of the proposal. The
justification should include rationale describing how the proposed alternative protects
human health and the environment using current and forecasted environmental conditions
and best available technology. The Director's staff will conduct a review of the
justification and may request additional information. The Director's staff will make a
recommendation to the Director, and any alternatives that are approved are recorded in
the administrative record.
2. Class VII Landfill Comments
2.1 Leachate
Comment: The key distinction between Class VII landfill facilities regulated per R315-321
and solid waste surface impoundments regulated per R315-322 is that solid waste surface
impoundments are permitted to accept high liquid waste without treatment, while Class
VII landfills are either not permitted to accept such high liquid wastes or much treat such
wastes to stabilize the free liquid content of such wastes. Solid waste surface
impoundments mandate more robust engineering controls and operating requirements
(engineered impermeable liners, leak detection, etc.) due to the higher mobility of E&P
wastes with free liquids. DWMRC states in their “Response to Comments” document that
most Class VII landfills are or are expected to be located “in arid areas of the state,” but
even “arid areas of the state” can be impacted by major storm events that could leach
contaminants from uncovered active landfill cells. Weather records for Vernal, Utah (a
representative location in the Uinta Basin where Class VII landfills are or will likely be
located and weather records are readily available) indicate that recorded daily
precipitation is as high as 2.2 inches and daily snowfall is as high as 16.0 inches. Thus,
wastes that are disposed of at Class VII landfill facilities without free liquids at the time
of acceptance could potentially generate leachate by direct precipitation even if the run-
on controls prescribed in R315-303-3(1)( c) are followed. Further, Class VII landfill
facilities could potentially accept high liquid waste without treatment as required by
R315-303-3(1.1)(a) inadvertently or even intentionally. Thus, regulations for Class VII
landfill facilities should assume that Class VII landfills will generate leachate.
The potential for Class VII landfill waste to generate leachate via precipitation,
acceptance of high liquid waste inappropriately, or via other mechanisms should be
considered in the design and operations standards for all Class VII landfill facilities. By
the time a monitoring system detects groundwater pollution by landfill leachate,
widespread groundwater pollution would have already occurred. Remediation of this
potential groundwater contamination will come at a cost that far exceeds the cost of
preventing such contamination, and may be effectively impossible.
Response: As defined in Section R315-301-2, " 'Leachate' means a liquid that has passed
through or emerged from solid waste and that may contain soluble, suspended, miscible,
or immiscible materials removed from the waste." A need for groundwater monitoring at
a landfill is not based solely on a landfill generating leachate. It includes but is not
limited to the evaluation of federal and state requirements, waste generation source and
waste characteristics, facility location, quantity of waste received at the facility, aquifer
characteristics and the depth to the aquifer beneath the facility, prohibition of free liquids
disposal, and other operational requirements, among others.
If a facility monitors groundwater according to Rule R315-308, when contamination is
detected for an extended period, the facility must enter the corrective action program
detailed in Section R315-308-3. This requires the facility to remedy the contamination.
Similarly, for facilities performing leak detection outlined in Subsection R315-322-5(13),
any leak detection will require repair. The Division of Waste Management and Radiation
Control (DWMRC) maintains that one or the other is sufficient for environmental
protection.
2.2 Liner Requirements
2.2.1 Rule Reference to Liners
Comment: R 315-302 -2 v(e)(I)(A)(B): This reference clarifies the groundwater conditions
required when a liner is not required for a landfill. If you could provide the reference in
the code that determines when a liner is or is not required for a landfill that would be
appreciated.
Response: Rule R315-303 provides liner requirements for facilities under the “Landfilling
Standards.” The applicability statement for the Rule, found in R315-303-1, includes
Subsection (4), which states, “Class VII Landfills as specified in Rule R315-321.”
Accordingly, only the requirements of Rule R315-303 specified within proposed Rule
R315-321 are applicable to Class VII landfills. Proposed Rule R315-321 does not
reference the liner standards in Subsection R315-303-3(4), and therefore liners are not
required for Class VII landfill cells, unless a new or laterally expanding Class VII landfill
does not meet the location standards found in Subsection R315-302-1(2)(e). Utah Admin.
Code R315-321-3(1)(b). For more information, please see Section 2.2 of this response
document.
2.2.2 Liners (R N Industries, Inc. (RNI))
Comment: RNI requests that DWMRC require liners with leak detection systems for landfills.
Liners with leak detection are necessary to provide adequate environmental protection for
E&P landfills, which can generate leachate and impact surface and groundwater
resources. Best industry practice calls for liners. RNI submits the attached white paper on
the impact of E&P wastes and salts in particular that can degrade any clay soils or layers
beneath a landfill and impair their ability to keep contaminants contained in the landfill.
RNI also adopts and incorporates herein the comments filed by Integrated Water
Management (IWM), which provide additional technical and legal grounds in support of
a liner requirement.
Response: Please see DWMRC’s response to IWM’s comments, specifically its response
under Section 2.2.7 of this response document. See also Section 6.1 of this response
document about impacts of high salinity on clay.
2.2.3 Liners (Integrated Water Management, LLC (IWM))
Comment: DWMRC’s justification for omitting a liner requirement is that the expected waste
materials will not present a threat to the environment, based on its (i.e., Mr. Brian
Speer’s) assertion that (1) the involved soils are relatively impermeable, and (2) the
groundwater is relatively deep. Mr. Speer actual language, however, is itself very
uncertain and equivocal -- “Most Class VII landfill cells are located (or expected to be
located) in arid areas of the state where groundwater resources are not prevalent,
groundwater tables are deep, and natural silts and clays provide varying degrees of
inherent protection.” DWMRC’s Response to Comments, p.13. Even if “most” Class VII
landfills are located in arid areas, some will not be; even if the groundwater in the
expected locations is not “prevalent,” it is still present at substantial quantities that
constitute an important resources for groundwater users; even if the groundwater tables
are “deep” relative to other groundwater tables in the state, the groundwater tables are
still shallow enough to constitute and important resources for groundwater users in the
area; even if the natural silts and clays provide “varying” degrees of inherent protection,
where those varying degrees vary toward the lower end of protection, that degree of
protection will be minimal and inadequate to protect the groundwater resource. It is no
consolation for the actual users who need the protection of their groundwater resource in
this area of the State to know that the groundwater resource in other areas is not so
prevalent and do not need protection, or that the groundwater tables in other areas of the
State are deeper and do not need protection, or that the silts and clays in other areas of the
State do provide adequate degrees of protection.
Mr. Speer essentially acknowledges that some areas of the State may well need the
groundwater protection that would be afforded by a liner requirement. After noting that
“many” landfills are located “in arid areas of the state where groundwater resources are
not prevalent, groundwater tables are deep, and natural silts and clays provide varying
degrees of inherent protection,” he immediately acknowledges “[h]owever…, the
Director has full discretion to require a liner. The current regulatory structure is
preferable to a structure where liners are always required but provides operators the right
to seek exemptions and variances from the liner requirement due to site-specific
conditions.” DWMRC’s Response to Comments, p.13. This approach of defaulting to a
presumption of invulnerability (don’t require protection unless it can be demonstrated it
is needed) rather than a presumption of vulnerability (require protection unless it can be
demonstrated it is not needed) is contrary to most analogous environmental protection
regimes. See, e.g., R649-9 (DOGM’s Waste Management and Disposal Rules imposing
certain requirements and standards (including liners), but allowing requests for variances
from Director when warranted by the particular circumstances); U.C.A. § 19-2-113 (Utah
Air Conservation Act mandating various permits and requirements, but allowing
variances when certain conditions are present); 49 U.S.C. 5101 et seq. (federal hazardous
materials regulations requiring permits for transportation of hazardous materials, but
allowing variances if certain circumstances can be demonstrated).
IWN is certainly not suggesting that liners be required for every E&P waste landfill;
rather, IWN is proposing that the default presumption be one of vulnerability (requiring a
liner unless it is demonstrated one is not needed) rather than invulnerability (not requiring
liner unless it is demonstrated one is needed). IWN is simply requesting that the default
presumption and the burden of proof be switched.
Response: DWMRC first clarifies that comments attributed to Mr. Speer should be attributed
to DWMRC, whose six authors of the responses discussed above should be counted as a
whole and a result of serious study and consideration. Most Exploration & Production
(E&P) waste landfill cells are located, or are expected to be located, in arid areas of the
state where groundwater resources are not prevalent, groundwater tables are deep, and
natural silts and clays provide varying degrees of natural protection. The location
requirements for a new or laterally expanding Class VII landfill include the standards for
groundwater found in Subsection R315-302-1(2)(e). In addition, new or laterally
expanding Class VII landfills must meet the location requirements of Subsection R315-
302-1(2)(e)(iv).
Moreover, high liquid waste is prohibited from being disposed of in any Class VII
landfill cell. See Proposed Utah Admin. Code R315-303-3(2). For solid waste surface
impoundments, used to dispose of high-liquid wastes, a liner system is required with the
point of compliance between the liners. See Proposed Utah Admin. Code R315-322-
5(12). Yet, at the same time and as discussed in more detail below, the Director still
maintains full discretion to require liners for E&P waste landfill cells under the Water
Quality Act, Utah Code § 19-5-101 et seq., and based on site-specific conditions.
Administrative convenience is one of the reasons the proposed rules do not contain a
prescriptive liner requirement. The current regulatory structure is preferable to a structure
where liners are always required but owners and operators have the right to seek
exemptions and variances from the liner requirement due to site-specific conditions. In
practice, the current regulatory structure is intended to reduce DWMRC’s permit
processing times and the resources the regulated community may require to develop a
permit application. Accordingly, the current regulatory structure benefits DWMRC and
the regulated community while protecting human health and the environment.
2.2.4 Liners (IWM)
Comment: To meet the standards for performance for groundwater as specified in Section
R315-303-2(1) as required by R315-321-2(1), Class VII landfill facilities should be
required to implement and maintain impermeable liners equivalent to the liner
requirements for surface impoundments per R315-322-5(12). A regulatory structure
where liners are required, but allows operators the right to seek exemptions and variances
from the liner requirement due to site-specific conditions, would be consistent with
DWMRC standards for Class I through Class VI landfills and E&P waste landfills in
most other states. process and includes drilling mud. Thus, it appears potassium chloride-
based drill muds are an exempt E&P waste acceptable for disposal at E&P waste facilities
in Utah.
Response: The standard of performance for groundwater found in Subsection R315-303-2(1)
states: “An owner or operator of a disposal facility shall not contaminate the ground
water underlying the facility beyond the ground water quality standard set in Section
R315-308-4 or, for constituents not set in Section R315-308-4, as established by the
Director based on health risk standards.” The rules prescribe certain location standards
found in Subsection R315-302-1(2)(e), run-on and run-off control found in Subsection
R315-303-3(1), closure requirements including final cover and post-closure care
requirements found in Section R315-303-3, and when hazardous waste is received (from
a very small quantity generator), groundwater monitoring as found in Subsection R315-
321-4(3). These measures provide protections to groundwater that are consistent with the
Solid and Hazardous Waste Act and federal requirements. However, an owner or operator
who identifies other benefits which may result from installing liners, or other engineering
and operational controls, may do so when those measures are not less restrictive than the
rules.
See Section 2.2.3 of this response document for the response to regulatory structure; See
Section 2.2.6 of this response document for the response to neighboring states requiring
synthetic liners; and see Section 2.2.7 of this response document for other relevant
discussion on liners.
As to liner requirement consistency with DWMRC standards for Class I through VI
landfills. These landfill classifications include two subclasses, and Rule R315-319
provides for coal combustion residual landfills, making a total of nine landfill design
standards in the current rules. Of these nine, three are required to have liners: municipal
solid waste landfill Class I and Class V, and coal combustion residual landfills. The liner
requirement for these landfill classes are consistent with federal regulations for the waste
accepted.
Lastly, the comment above includes the statement, “Thus, it appears potassium chloride-
based drill muds are an exempt E&P waste acceptable for disposal at E&P waste facilities
in Utah.” The statement is not complete. It is important to understand that potassium
chloride-based drill muds only qualify as exempt from the hazardous waste requirements
if the waste is generated intrinsically from the exploration, development, or production of
oil, gas, or geothermal energy.
2.2.5 Liners (IWM)
Comment: The industry standard is for such solid waste E&P landfills to include liners. See
EPA’s Requirements/Best Practices Letter addressed in detail below (“Landfills should
be designed and constructed per industry standard, to include appropriate composite liner
systems”), and DWMRC’s webpage addressed in detail below (“Landfill standards often
include lined cells”). IWM’s consultants that assisted in connection with the preparation
and permitting of IWM original landfill (“IWM Landfill”) and its anticipated new landfill
(“Pinnacle Fuels Landfill”) have confirmed in their above-referenced and attached
comments that the industry practice for solid waste E&P landfills is to include a liner.
It is notable that the Utah Petroleum Association, which represents the interests of the
Utah broad oil and gas industry, has submitted written comments in DWMRC’s initial
rulemaking phase, and again now in the Board’s rule-making process, emphatically
advocating for a liner requirement. Other individual members of the Utah oil and gas
industry have also submitted written comments advocating for a liner requirement. Even
more notable, IWM is not aware of ANY member of the Utah oil and gas industry, or any
other industry, that has submitted comments opposed to a liner requirement.
Response: These comments seem to overlook the fact that under the solid waste surface
impoundment rules, E&P waste facilities that dispose of or manage high liquid wastes are
subject to very conservative liner requirements, with the point of compliance located
between the liners. See Proposed Utah Admin. Code R315-322-5(12).
Certain other types of landfills permitted by DWMRC also require liners. These liner
requirements align with federal law, which, as discussed in more detail below, require
liners for Municipal Solid Waste Landfills (MSWLF) under 40 C.F.R. § 258 and Coal
Combustion Residual (CCR) Landfills, 40 C.F.R. § 257, Subpart D. While DWMRC
responds more fully to the EPA Requirements/Best Practices Letter below, it recognizes
here that the letter includes no clear justification as to how or why the standards
applicable to CCR Landfills are similarly applicable to E&P Waste Landfills.
Moreover, DWMRC’s landfill liner requirements are fundamentally predicated upon the
type of waste those facilities accept. Class I and Class V Landfills require a liner because
they may accept municipal solid waste. Utah Admin. Code R315-301-2(7)(A)(i)
(providing that Class I Landfills are permitted by the Director to receive for disposal
municipal solid waste); and Utah Admin. Code R315-301-2(11)(a) (providing that Class
V Landfills are permitted by the director to receive for disposal municipal solid waste).
Not only does this standard align with federal law, but it also aligns with the
understanding that leachate from a MSWLF is inevitable. CCR Landfills similarly require
a liner. Utah Admin. Code R315-319-70(a)(1). Again, this requirement aligns with
federal law and the understanding that CCR is highly permeable and likely to produce
leachate. These standards are distinguishable from E&P waste landfill cells, which (1) are
explicitly prohibited from accepting high liquid waste, (2) will be used to dispose of low
permeability waste, and (3) are expected to be located in arid areas of the state where
groundwater resources are not prevalent, groundwater tables are deep, and natural silts
and clays provide varying degrees of inherent protection.
2.2.6 Liners (IWM)
Comment: The Proposed E&P Landfill Rule’s omission of a liner requirements is contrary
not just to the EPA’s instructions and best practices, as addressed immediately below, but
it is contrary to the requirements in most of the States in the country, including states
surrounding Utah. Some of those states have an outright synthetic liner requirement. [The
only State IWM is aware of that does not require a liner for such E&P-type waste is
Oklahoma.] See, for example, Colorado’s 6 CCR 1007-2, Part 1, Section 17.3.1(A)
(Design, Construction and Operation requirements mandating composite liner system for
managing E&P waste); New Mexico’s Solid Waste Management General Requirements,
Section 20.9.4.13.A (“special waste [which includes industrial solid waste, petroleum
contaminated soils, sludge, etc.] landfills shall provide a containment layer beneath the
solid waste which is constructed: (1) with a composite liner….”); Idaho’s Solid Waste
Management Rule 58.02.06.009 (providing that smaller landfills, Tier I and Tier II
landfills (less than 600 or 2000 cubic yards) are not required to have liners, but “Tier III
facilities shall … install leachate collection systems, liners, air containment control
systems and any applicable Tier III facility specific requirements.”). Other of those states
have an option for either a synthetic liner, or an equivalent liner where it can be
affirmatively demonstrated that the liner ensures groundwater protection standards are
satisfied. See, for example, Texas’ Rule 335.590(24)(A)(i) allows either a “composite
liner” or “a design that ensures that the concentration values … will not be exceeded in
the uppermost aquifer….”
Response: IWM argues that “the Proposed E&P Landfill Rule’s omission of a liner
requirements is contrary...to the requirements in most of the States in the country,
including states surrounding Utah.” IWM specifically points to four states it suggests
demonstrate “an outright synthetic liner requirement,” including Colorado, New Mexico,
Idaho, and Texas. IWM concedes that Oklahoma does not require liners for E&P waste
landfills. For the following reasons, the Director disagrees with IWM’s conclusion that
Colorado, New Mexico, Idaho and Texas maintain a prescriptive liner requirement for
E&P waste landfills.
IWM argues that Colorado requires liners for E&P waste landfills under 6 Colo. Code
Regs. 1007-2:1-17.3. 6 Colo. Code Regs. 1007-2:1-17.3 requires “each waste
impoundment covered by this section [to] be lined with a composite liner.” However,
under Colorado’s regulations, a “waste impoundment” is a “pit, pond, lagoon, trench, or
diked area.” 6 Colo. Code Regs. 1007-2:1-1.2. Colorado’s definition of landfill expressly
exempts “waste impoundments.” 6 Colo. Code Regs. 1007-2:1-1.2. Accordingly,
Colorado does not require liners for E&P waste landfills. Instead, Colorado requires
liners for pits, ponds, lagoons, trenches, and diked areas, all of which are intended to
accept liquid waste. Utah’s E&P waste landfills are prohibited from accepting high liquid
waste. See Proposed Utah Admin. Code R315-321-4(2)(c). Moreover, like Colorado’s
requirements, Utah’s proposed solid waste surface impoundment regulations, Utah
Admin. Code R315-322, require liners. See Proposed Utah Admin. Code R315-322-
5(12).
IWM argues that New Mexico requires liners for E&P waste landfills under New Mex.
Admin. Code 20.9.4.13. New Mex. Admin. Code 20.9.4.13 states “all new municipal and
special waste landfills and lateral expansions to existing municipal and special waste
landfills shall provide a containment layer beneath the solid waste which is
constructed...with a composite liner.” However, New Mex. Admin. Code 20.9.4.13 is
applicable to municipal landfills, special waste landfills, and monofills. Municipal
landfills, special waste landfills, and monofils are not authorized to accept E&P waste.
New Mexico defines “Special waste” as solid waste treated characteristic hazardous
wastes, packing house and killing plant offal, asbestos waste, ash from certain
incinerators, infectious waste, sludge, industrial solid waste, wastes from spills of certain
chemical substance, and petroleum contaminated soils that have certain constituent
levels. E&P waste is not “special waste.” Nor is E&P waste municipal solid waste.
Moreover, New Mexico excludes E&P waste from its definition of “solid waste.” New
Mex. Admin. Code 20.9.2.7.S.(9)(a); N.M. Stat. § 74-9-3.N.(1). Therefore, New Mexico
does not maintain a prescriptive liner requirement for E&P waste landfills.
IWM argues that Idaho requires liners for E&P waste landfills under Idaho Admin. Code
R58.01.06.009.04. Idaho Admin. Code R58.01.06.009.04 requires liners for Tier III
facilities. Idaho may determine that a facility is a Tier III facility if the facility is (1)
landfilling or disposing of VSQG hazardous waste; (2) landfilling or disposing of
materials with a high human pathogenic potential; (3) managing solid waste in a manner
or volume that will form toxic leachate or gas; or (4) managing solid waste in a manner
or volume that is likely to pose a substantial risk to human health or the environment. Id.
The Tier III facilities that require liners are petroleum contaminated soil processing
facilities and non-municipal solid waste facilities. Idaho Admin. Code
R58.01.06.013.13.c.ii. E&P waste landfills are not petroleum contaminated soil
processing facilities. Idaho Admin. Code R58.01.06.005.31. E&P waste landfills do not
clearly qualify as non-municipal solid waste facilities, and the liner requirements for Tier
III non-municipal solid waste facilities do not require synthetic liners. Idaho Admin.
Code R58.01.06.013.13.c.ii. Therefore, Idaho does not maintain a prescriptive liner
requirement for E&P waste landfills.
IWM argues that Texas requires liners for E&P waste landfills under 30 Tex. Admin.
Code 335.590(24)(A)(i). 30 Tex. Admin. Code 335.590(24)(A)(i) requires commercial
industrial nonhazardous waste landfill cells to be designed and constructed with a
composite liner and a leachate collection system. Texas’ industrial nonhazardous waste
landfills are authorized to accept industrial nonhazardous waste, which is defined as
“[s]olid waste resulting from or incidental to any process of industry or manufacturing, or
mining or agricultural operation, which may include ‘Hazardous waste’ as defined in this
section.” 30 Tex. Admin. Code 335.1(92). Notably absent from this definition is
exploration and production waste or any mention of waste associated with oil and gas
production. Id. This may be due, in part, to Texas’ exclusion of E&P waste from its
definition of “solid waste.” 30 Tex. Admin. Code 335.1(160)(A)(iii); Tex. Health & S.
Code § 361.003(34)(A)(iii). In fact, E&P waste is regulated by the Railroad Commission
of Texas. 16 Tex Admin. Code 3.30(2)(A). The Railroad Commission of Texas only
requires liners for “non-commercial fluid recycling pits,” which are pits intended to
accept liquids or fluids. 16 Tex. Admin. Code 3.8(4)(G). Like Texas’ requirements,
Utah’s proposed solid waste surface impoundment regulations, Utah Admin. Code R315-
322, require liners. Utah Admin. Code R315-322-5(12). Therefore, Texas does not
maintain a prescriptive liner requirement for E&P waste landfills.
Finally, and as discussed further below, it’s important to recognize that insofar as EPA is
concerned, States are free to implement standards more stringent than federal law,
including landfill liner standards. 40 C.F.R. § 239.2(a)(1). In any event, the regulatory
programs in other states appear to be distinguishable from Utah’s approach, which
includes a clear distinction between the disposal of high liquid waste, which requires a
conservative liner system, and disposal of E&P wastes that are not high liquid wastes,
low-permeability, and stable. Therefore, the State regulations IWM attempts to use to
exemplify express liner requirements for E&P waste landfills in other states do not
demonstrate Utah’s requirements are contrary to “most of the States in the country.”
2.2.7 Liners (IWM)
Comment: On October 18, 2023, the U.S. Environmental Protection Agency (“EPA”) issued a
formal letter captioned Federal Requirements and Best Practices for Oil and Gas Waste
Management Facilities, addressed to “Owners and Operators of Oil and Gas Waste
Facilities Managing Exploration and Production Wastes.” The attachment to that Letter
summarizes EPA’s instructions regarding the various applicable requirements and best
practices (“Requirements/Best Practices Letter”) for the design of landfills. In that
portion of the Letter relating to “Landfills,” EPA emphatically asserts that “Landfills
should be designed and constructed per industry standard, to include appropriate
composite liner systems and leak detection to ensure the protectiveness required under
part 257 [of the Resource Conservation and Recovery Act (“RCRA”)].”
Requirements/Best Practices Letter, p.2, attached as Exhibit.
Response: IWM suggests that the federal regulations and the U.S. Environmental Protection
Agency’s (EPA) letter dated October 18, 2023, amount to a persuasive authority that
E&P waste landfills “should be designed and constructed per industry standard, to
include appropriate composite liner systems and leak detection to ensure the
protectiveness required under part 257 [of the Resource Conservation and Recovery
Act].”
First, the DWMRC appreciates EPA's letter and acknowledges that the best practices
identified therein are recommended to “help ensure compliance with the RCRA
requirements...depending on site-specific conditions.” These best practices are
commendable, and the Proposed E&P Waste Rules include groundwater monitoring
requirements for facilities that receive hazardous waste from very small quantity
generators, as contemplated by 40 C.F.R. § 257, Subpart A. However, the liner
requirements for Coal Combustion Residuals landfills (CCR landfills) under 40 C.F.R. §
257, Subpart D, are inapplicable because E&P waste landfills may not accept CCR.
Although not directly mentioned in EPA’s letter, the liner requirements for municipal
solid waste landfills (MSWLF) under 40 C.F.R. § 258, are also inapplicable to E&P
waste landfills because E&P waste landfills may not accept CCR nor municipal solid
waste. See Proposed Utah Admin. Code R315-321-4(4)(b).
The federal CCR landfill requirements are codified under 40 C.F.R. § 257, Subpart D.
Under 40 C.F.R. § 257.70(a)(1), a new or expanding CCR landfill “must be designed,
constructed, operated, and maintained with either a composite liner...or an alternative
composite liner.” A CCR landfill is a landfill that receives coal combustion residuals
(CCR). 40 C.F.R. § 257.53. Importantly, CCR is defined as “fly ash, bottom ash, boiler,
slag, and flue gas desulfurization materials generated from burning coal for the purpose
of generating electricity by electric utilities and independent power producers.” 40 C.F.R.
§ 257.53. E&P waste is not CCR, and the liner requirements under 40 C.F.R. § 257,
Subpart D, are inapplicable to E&P waste landfills.
The federal MSWLF unit requirements are codified under 40 C.F.R. § 258. Under 40
C.F.R. § 258.40(a)(1), new or expanding MSWLF units “shall be constructed with a
composite liner.” A MSWLF unit is “a discrete area of land or an excavation that receives
household waste, and that is not a land application unit, surface impoundment, injection
well, or waste pile.” 40 C.F.R. § 258.2. Household waste is defined as “any solid waste
(including garbage, trash, and sanitary septic tanks) derived from households.” 40 C.F.R.
§ 258.2. E&P waste is not household waste, and the liner requirements under 40 C.F.R. §
258 are inapplicable to E&P waste landfills.
Second, high liquid waste is prohibited from being disposed of in any Class VII landfill
cell and must be managed appropriately. See Proposed Utah Admin. Code R315-303-
3(2); see also Proposed Utah Admin. Code R315-321-4(3)(c). High liquid waste is
“nonhazardous solid waste that is liquid in its natural state, contains free liquids, or is
expected to liquefy or vaporize under the circumstances that is managed or disposed.”
Proposed Utah Admin. Code R315-301-2(27). However, the prohibition against
disposing of high liquid waste is but one control to protect groundwater. The proposed
rules include other controls to protect groundwater, including run-on and run-off, final
cover, and post-closure monitoring. See Proposed Utah Admin. Code R315-321-4(3)(a),
(d), (e); see also Proposed Utah Admin. Code R315-321-4(2). The provisions in the draft
rule both protect groundwater and ensure the long-term stability of Class VII landfill
cells.
Moreover, unlike Class VII landfills, liners are required for new or expanding solid waste
surface impoundments under proposed Utah Admin. Code R315-322. The waste disposed
of in an E&P waste landfill is fundamentally distinct from the waste disposed of in a
surface impoundment. Solid waste surface impoundments may accept high liquid waste,
leachate, or sludge and need only comply with the high liquid waste management
requirements under Utah Admin Code R315-303-3(1) if a dewatering or other
stabilization technique is used in association with the solid waste surface impoundment.
See Proposed Utah Admin. Code R315-301-2(71); see also Proposed Utah Admin Code
R315-322-5(4). The distinction between liner requirements for E&P waste landfills and
liner requirements for solid waste surface impoundments addresses the type of waste
accepted in the respective facilities and the associated risks.
Finally, the Director of DWMRC may require a liner for certain E&P waste landfills.
First, the Director of DWMRC is the statutory “Director” under the Water Quality Act,
Utah Code § 19-5-101 et seq., and the rules promulgated thereunder for groundwater
protection at any facility licensed by and under the jurisdiction of DWMRC. Utah Code §
19-5-102(6). Pursuant to this statutory directive, the Director has the authority and
regulatory tools necessary to protect groundwater through permitting, enforcement, and
corrective actions. The Director’s authority includes the duty and ability to require liners,
monitoring, and other measures necessary to protect groundwater resources at E&P
facilities through rules outside of the proposed solid waste rules. See Utah Admin. Code
R317-6 et seq. In short, the substance of the groundwater protection program under the
Water Quality Act applies to Class VII landfills and solid waste surface impoundments,
as implemented by the DWMRC Director. Second, as mentioned above, a new or
laterally expanding Class VII landfill that does not meet the location standards found in
Subsection R315-302-1(2)(e) may be required to have a liner. Utah Admin. Code R315-
321-3(1)(b).
Accordingly, DWMRC’s design standards for E&P waste landfills align with federal law,
the Director’s statutory authority under the Water Quality Act, and the distinct nature of
waste accepted by such facilities.
2.2.8 Liners (IWM)
Comment: Adding a liner requirement for such E&P waste landfills would not render the
Proposed E&P Waste Landfill Rule “more stringent than the corresponding federal
regulations which address the same circumstances,” which would ordinarily be prohibited
under UCA § 19-6-106(1). First, there are no “corresponding federal regulations which
addresses the same circumstances,” as the federal regulations neither expressly require or
expressly exempt a liner for such E&P waste; rather, they are simply silent on the matter.
A Utah liner requirement would not conflict with any federal regulation, it would simply
fill the void in the federal regulations. Moreover, it would fill the void that the above-
referenced EPA Requirements/Best Practices Letter clarified by emphasizing that
“Landfills should be designed and constructed per industry standard, to include
appropriate composite liner systems and leak detection...” Notably, as to those many
States that have imposed liner requirements, the EPA has not deemed any of those
requirements to be “more stringent than the corresponding federal regulations...” Any
suggestion that the EPA would even consider doing so for a Utah liner requirement is
extremely implausible given the EPA Requirements/Best Practices Letter and its
emphasis that “Landfills should be designed and constructed per industry standard, to
include appropriate composite liner systems.”
Response: Under the Division of Waste Management and Radiation Control Board’s (the
Board) rulemaking authority, the Board may not promulgate rules that are more stringent
“than the corresponding federal regulations which address the same circumstances.” Utah
Code § 19-6-106(1). The Board may promulgate rules more stringent than the
corresponding federal regulations if the Board makes specific findings after public
comment and hearing and based on evidence in the record that the corresponding federal
law is not adequate to protect human health and the environment. Utah Code § 19-6-
106(2). 40 C.F.R. § 257, Subpart A, is the federal regulation that corresponds to the
DWMRC’s proposed Utah Admin. Code R315-321 et seq. Landfills are not required to
have liners under 40 C.F.R. § 257, Subpart A. DWMRC is not aware of a compelling
reason to conclude that federal law is inadequate to protect Utah’s environment, in large
part because the Director may require the installation of liners and other appropriate
controls to protect groundwater at E&P waste landfills where conditions warrant such
protections.
Under 40 C.F.R. § 239.2(a)(1) a state may adopt or enforce requirements “that are more
stringent or more extensive” than federal law. If a state is to adopt requirements more
stringent than federal law, EPA is not required to deem those requirements so. Indeed, the
Board’s authority to adopt rules that are no more stringent than federal law is a facet of
state law. See Utah Code § 19-6-106. While federal law authorizes a state to adopt
requirements more stringent than federal law, the Utah legislature limited that authority.
Id. The consideration is not whether EPA would deem the state requirements more
stringent than federal law, the consideration is whether requiring liners for E&P waste
landfills would be more stringent than the corresponding federal regulations. As
discussed above, liners are not required under federal law, and thus, absent specific
circumstances, the Board lacks authority to promulgate a rule requiring liners for E&P
waste landfills.
Additionally, the proposed rules include a conservative liner requirement for the disposal
of high liquid E&P wastes in solid waste surface impoundments. See Proposed Utah
Admin Code R315-322-5(12). This requirement is based on best available technology
(BAT) requirements under the Utah Water Quality Act, Utah Code § 19-5-101 et seq.,
and Utah Admin. Code R317-6 and the permit by rule under Utah Admin. Code R317-6-
6. These standards are based on the premise that the solid waste rules impose the same
substantive requirements as would apply under a groundwater discharge permit. As
discussed above, the Director’s authority under the Utah Water Quality Act includes the
ability to require liners, monitoring, and other measures necessary to protect groundwater
resources at E&P facilities. This basis is consistent with the rationale underlying the liner
system required for evaporation facilities under the Board of Oil, Gas, and Mining Rules.
See Utah Admin. Code R649-9-4(7).
The comments suggesting that the Board adopt rules that are more stringent than federal
law apply only to E&P waste landfills that accept wastes that do not qualify as high liquid
waste. These comments have not carried their burden of demonstrating that federal law is
inadequate to protect human health and the environment as to the disposal of non-high-
liquid E&P waste in E&P waste landfills.
2.2.9 Liners (IWM)
Comment: The Utah Division of Oil, Gas & Mining (DOGM) has historically had primary
responsibility for the permitting and regulating of the disposal of solid waste, including
E&P related waste. Those Rules include detailed requirements for the installation of
liners, the procedures for detecting and responding to liner failures, the repair and
inspection of liners, and the closure-related methods for disposal of liners. See, e.g.,
R649-9-10.2; R649-9-11.4; R649-9-11.4.1; R; 649-9-12.1.4. Starting in 2013, that
responsibility started shifting from DOGM to DWMRC, and DWMRC started permitting
E&P waste landfills in 2014. Upon assuming that responsibility, DWMRC continued
with the long-established industry practice, and DOGM’s long-established rule, of
requiring a liner for such E&P waste. Indeed, from 2013 through 2019, it issued permits
for multiple new or expanded E&P waste landfills, all of which required liners.
Note on Similar Comments: IWM furthers this theme throughout its comments by discussing,
in varying levels of detail, “DWMRC’s Acknowledgement of Having Required Liners,”
“IWM’s 2014 Conversion of Lined Pond to Lined Landfill,” and “DWMRC
Communication with IWM on Developing Second Cell.” IWM also suggests that
“Important Policy Objectives Will be Achieved by Requiring Liners.” DWMRC responds
to these general comments here.
Response: In 2019, the Utah State Legislature passed House Bill 310, which removed the
exclusion of “drilling muds, produced waters, and other wastes associated with the
exploration, development, or production of oil, gas, or geothermal energy” from the Utah
Solid and Hazardous Waste Act’s definition of solid waste. H.B. 310, 63rd Leg., Gen
Sess. (Ut. 2019). This legislative change became effective on May 14, 2019, and resulted
in DWMRC having the obligation to enforce the Act and the solid waste rules as to all
E&P waste operations in the state. To effectuate this obligation, jurisdiction over E&P
waste facilities was required to transfer from the Division of Oil, Gas, and Mining
(DOGM) to the WMRC.
DOGM neither exercised jurisdiction over nor permitted landfills. DOGM’s rules
primarily regulated the disposal of E&P waste through two facility types—evaporation
facilities and landfarms. Evaporation facilities are facilities designed and maintained to
manage liquid waste by separating oil from produced water prior to discharge to a pond
Utah Admin. Code R649-9-4(2.2). Landfarms are facilities that bioremediate oil
contaminated soils and materials through the application of microbes and nutrients. Utah
Admin. Code R315-R649-9-5(1). Evaporation facilities require a liner. Landfarms do not
require a liner. Again, this practice likely aligns with the type of waste each facility was
authorized to accept. Evaporation facilities were authorized to accept liquid waste. Utah
Admin. Code R649-9-4(3.1), -4(6.1). Landfarms were not authorized to accept liquid
waste. Utah Admin. Code R649-9-5(2.1), -5(2.2). Accordingly, DOGM never exercised
jurisdiction over or permitted landfills, and its liner requirements were limited to
evaporation facilities that accept liquid waste.
Landfills are not designed to receive unbounded amounts of free liquids, as found in 40
C.F.R. § 258.23 and Utah Admin. Code R315-303-3. Each owner and operator of an
E&P landfill permitted by DWMRC through 2023 had a landfarm permitted by DOGM
prior to applying for a DWMRC landfill permit. Each operator also had a history of
failing to meet DOGM’s rule which says “E and P waste accepted by the landfarm shall
be sufficiently free of liquid content to pass a 60-mesh liquid paint filter test.” See Utah
Admin. Code R649-9-5(2.1); Division of Oil, Gas and Mining letter, March 24,
2009,“Notice to Oil & Gas and Disposal Facility Operators”; Division of Oil, Gas and
Mining letter, October 18, 2012, “Notice to Oil & Gas and Disposal Facility Operators”;
Division of Oil, Gas and Mining letter, April 4, 2018, “Waste Disposal and Landfarm
Procedures.”
These circumstances, among others, led DWMRC to require liners at certain E&P
landfills permitted between 2013 and 2023 because of the historical failure of the facility
operator to exclude waste containing free liquids. Further, after receiving landfill permits
from DWMRC, inspections demonstrated that owners and operators continued to receive
waste not meeting similar requirements found in Subsection R315-303-3(1). To clearly
communicate requirements to operators who would potentially transition from being
permitted by DOGM to DWMRC, DWMRC sent letters to all E&P waste operators
(DSHW-2022-017208, Division of Waste Management and Radiation Control, July 29,
2022, “E&P Waste Free Liquids Standards and Best Management Practices.”) stating,
“both DOGM and DWMRC have long-standing rules that prohibit the acceptance of
waste containing free liquids at a landfarm or landfill. As written in the Utah
Administrative Code [R315-301-2(26), R315-303-3(1)(b), and R349-9-5 subsections 2.1
and 2.2], the acceptance of waste when liquids readily separate from the solid portion of
waste is prohibited. These rules provide a standard that waste must pass a 60-mesh paint
filter liquids test.” The DWMRC has seen marked improvement in management of free
liquids since the July 2022 letter mentioned above. DWMRC anticipates that through
frequent communication, increased inspections, and compliance actions, when necessary,
that the acceptance of free liquids at E&P landfills will be reduced.

2.2.10 Liners (IWM)
Comment: In an effort to justify its recent reversal from its historical practice of requiring
liners, DWMRC attempted to explain away the “differences when comparing the first
E&P waste landfills permitted in the Uintah Basin to those that will be permitted in the
future.” 2/28/24 email from DWMRC’s Brian Speer to IWM’s Nate Robinson, attached
as Exhibit. “First, the four E&P waste landfill permits that were issued between 2013 and
2019 from the DWMRC were issued at the request of the operators, and not because of
requirements under the Solid and Hazardous Waste Act.” Id. As addressed above, those
DWMRC-issued permits were not requested at the whim of the operators, but rather
because DOGM told those operators that responsibility for issuing such permits was
transferring to DWMRC and those operators would need to obtain such permits from
DWMRC, and DWMRC confirmed that it rather than DOGM would now be issuing such
permits. Mr. Speer continued his attempt to justify the reversal -- “Second, until at least
2022, most E&P waste landfill operators were having difficulty following the
requirements of their DWMRC permit to exclude free liquids from the landfill cells.
These circumstances may have influenced requirements and comments from DWMRC
staff regarding liners in E&P waste landfill cells.”4 This, however, is a further
acknowledgement that DWMRC has historically required, and communicated to
operators that it required, liners for such E&P waste landfills.
In summary, and as evident from the history recounted above, DOGM was transferring
its role and responsibility for permitting E&P waste to DWMRC, and DWMRC initially
recognized that it would need to continue the industry’s and DOGM’s long-established
practice of a liner requirement. DWMRC later realized this responsibility of evaluating
liners would take additional time, effort and oversight, and is now trying to shed that
newly-transferred responsibility because the federal program (40 C.F.R. § 257) neither
expressly requires nor expressly exempts such E&P waste landfills from a liner. DOGM
should not disregard industry practice, DOGM’s historical requirement or DWMRC’s
own historical practice of requiring liners for such E&P waste landfills simply because
the federal program does not expressly address the issue.
Response: The DWMRC stands by the statement made in the email from Mr. Speer on
February 28, 2024. That said, “the four E&P waste landfill permits that were issued
between 2013 and 2019 from the DWMRC were issued at the request of the operators,
and not because of requirements under the Solid and Hazardous Waste Act.” The
definition of solid waste exempted E&P waste until May 14, 2019. Next, the DOGM has
reviewed their records, and have been unable to find any record of communications to
operators, prior to the effective date of House Bill 310 passed by the Utah State
Legislature in 2019, that responsibility for issuing such permits was transferring to
DWMRC and those operators would need to obtain such permits from DWMRC. Please
see response in Section 2.2.9 in this response document for more information.
2.2.11 Liners (IWM)
Comment: In connection with its initial Draft E&P Rule, DWMRC prepared a separate Oil
and Gas Exploration and Production Waste Management webpage on its website to
explain the anticipated changes associated with its Draft E&P Rule, and therein included
a “FAQ” section. One of those questions is “What protection do landfills offer for the
environment?” Notably, its response expressly acknowledges that “Landfills are more
protective of the environment than landfarming or beneficial uses,” because of the “lined
cells” that landfill standards “often include.”
Response: IWM references DWMRC’s webpage, which included an answer to the
frequently asked question “What protection do landfills offer for the environment?”
DWMRC’s webpage stated that landfills, among other protections, often include lined
cells. As discussed in detail above, Class I and Class V Landfills are required to have
lined cells because those facilities accept municipal solid waste. Utah Admin. Code
R315-303-3(3). CCR Landfills are also required to have lined cells because those
facilities accept CCR. Utah Admin. Code R315-319-70(a)(1). Requiring these types
of facilities to have lined cells does not necessarily mean that other types of facilities
without lined cells are less protective of the environment. Nor does it necessarily
mean that DWMRC usually requires lined cells for facilities that are not Class I,
Class V, or CCR Landfills. Please see response in Section 2.2.5 in this response
document for more information.
2.2.12 Liners (IWM)
Comment: DWMRC’s existing solid waste rules for landfills have long required composite or
equivalent protective liners for all of the existing classes of landfills – Classes I-VI. See
Utah Admin. Rule R315-303-3(3). The Proposed E&P Landfill Rule’s omission of a liner
requirement for the new Class VII landfills would be contrary to well established
precedent requiring landfill liners in Utah. In addition, DWMRC’s Solid Waste Facility
Location Standard is structured such that, as a practical matter, almost all solid waste
landfills are required to have a liner. More specifically, that Location Standard provides
as follows:
(iv) Unless each unit of the proposed facility is constructed with a composite
liner or other equivalent design approved by the director:
(A) a new facility located above any aquifer containing groundwater that has
a TDS content below 1,000 mg/l that does not exceed applicable
groundwater quality standards for any contaminant is permitted only
where the depth to groundwater is greater than 100 feet; or
(B) a new facility located above any aquifer containing groundwater that has
a TDS content between 1,000 and 3,000 mg/l and does not exceed
applicable groundwater quality standards for any contaminant is permitted
only where the depth to groundwater is 50 feet or greater.

R315-302-1(2)(e)(iv)(emphasis added). In short, this Location Standard mandates that a
liner is required unless the proponent of a new or expanded facility can satisfy three
specified criteria – that the new facility is (1) “located above any aquifer containing
groundwater that has a TDS content below 1,000 mg/l,” (2) that said groundwater “does
not exceed applicable groundwater quality standards for any contaminant,” and (3) that
“the depth to groundwater is greater than 100 feet.” The great majority of existing and
anticipated new landfills in the subject vicinity do not satisfy those three criteria. Even if
some of those landfills may satisfy one or even two of those criteria, very few, if any, can
satisfy all three criteria.
In addition, DWMRC has analogous rules for Facility Standards for Piles Used for
Storage and Treatment. R315-314. Those rules contain specific “Requirements for Solid
Waste Likely to Produce Leachate,” like the E&P waste here, and among those is a
requirement that waste piles shall be placed on a “liner underlying the pile to prevent
subsurface soil and potential groundwater contamination and to allow collection of run-
off and leachate.” R315-314-2(2).
Response: IWM suggests that Class I-VI Landfills require liners, that the location standards
create a near per se rule requiring liners for all landfills, and waste piles likely to produce
leachate require liners.
As discussed above, DWMRC requires liners for Class I, Class V, and CCR Landfills.
The liner requirements for these types of landfills align with the types of waste these
landfills are authorized to accept—municipal solid waste and CCR. The liner
requirements for these types of landfills also align with federal standards, which similarly
require liners for municipal solid waste landfills and CCR landfills. See 40 C.F.R. 258;
See also 40 C.F.R. 257, Subpart D.
E&P waste landfills are subject to certain location standards under Utah Admin. Code
R315-302-1(2). Indeed, the Director may not provide exemptions at a Class VII landfill
for certain location standards. Proposed Utah Admin. Code R315-321-3(3)(b)(i)-(iv). As
such, where the depth to groundwater is greater than 100 feet, the new facility may be
located above any aquifer containing groundwater that has a TDS content below 1,000
mg/l that does not exceed applicable groundwater quality standards for any contaminant.
Utah Admin. Code R315-302-1(2)(e)(iv)(A). Where the depth to groundwater is 50 feet
or greater, the new facility may be located above any aquifer containing groundwater that
has a TDS content between 1,000 and 3,000 mg/l and does not exceed applicable
groundwater quality standards for any contaminant. Utah Admin. Code R315-302-
1(2)(e)(iv)(B). Notably, the applicant for the proposed facility is charged with making the
“demonstration of groundwater quality necessary to determine the appropriate aquifer
classification.” Utah Admin. Code R315-302-1(2)(e)(iv)(C).
Waste piles are a different type of solid waste management facility than E&P Waste
Landfills. Waste piles are discrete areas used for temporary storage or treatment of solid
waste. See Utah Admin. Code R315-301-2(56); Utah Admin. Code R315-314-1. On the
other hand, E&P Waste Landfills are used for the disposal of E&P waste. See Proposed
Utah Admin. Code R315-301-2(13) (Emphasis added). Accordingly, the liner
requirements for waste piles align with the purpose of those types of facilities. Those
requirements do not demonstrate that landfills permitted by DWMRC are required to
have liners.
2.2.13 Liners (IWM)
Comment: R315-303-3 specifies that all landfills have a liner and meet the design criteria of
using a synthetic primary liner. We understand that current Utah code allows scenarios
where synthetic liners may not be required. Not having a synthetic liner should be a last
resort allowance that is only approved after an extensive evaluation of subsurface
conditions that demonstrates liner equivalence. To approve solid waste disposal landfills
without a synthetic liner puts the operator, the regulator and Utah’s natural resources at
risk, and is bad for industry and the environment.
Similar Comment: UPA is concerned that the Proposed Rule would allow unlined oilfield
landfills or scenarios where a synthetic liner is not required. We believe that not having a
synthetic liner should be an allowance only approved after an extensive evaluation of
subsurface conditions that demonstrates liner equivalence. To approve solid waste
disposal landfills without a synthetic liner and without demonstration of equivalency
creates an unnecessary risk for producers that have cradle to grave liability for their
wastes. It is the industry standard to use synthetic liners for these types of disposal
facilities and we encourage the DWMRC to be balanced but forward- thinking in
regulating the industry’s standard of care.
Response: Please see Section 2.2.4 in this response document for information discussing the
classes requiring liners are Class I and Class V landfills, and CCR landfills.
2.2.14 Liners (IWM)
Comment DWMRC has attempted to analogize to and rely on Class IIIb landfills (whose
design standards do not require liners per R314-304-3(2) & R315-304-5(3)) as
justification for not requiring liners in the Proposed E&P Waste Landfill Rule. That
analogy and reliance is wholly misplaced, however, because Class IIIb landfills are “non-
commercial” landfills. R315-301-2(9).
Response: The commercial, non-commercial distinction under the Utah Solid and Hazardous
Waste Act, Utah Code § 19-6-101 et seq., primarily concerns whether a facility receives
solid waste for profit. Under Utah Code § 19-6-102(3)(a) a “‘[c]ommercial nonhazardous
solid waste treatment, storage, or disposal facility’ means a facility that receives, for
profit, nonhazardous solid waste for treatment, storage, or disposal.” On the other hand, a
non-commercial facility is one that “(i) receives waste for recycling; (ii) receives waste to
be used as fuel, in compliance with federal and state requirements; (iii) is solely under
contract with a local government within the state to dispose of nonhazardous solid waste
generated within the boundaries of the local government; or (iv) receives only waste from
the exploration and production of oil and gas.” Utah Code § 19-6-102(3)(b). Whether a
facility is commercial or non-commercial has little to do with the type of waste the
facility can accept or the design standards with which the facility must comply. For
example, a Class I Landfill is a noncommercial facility, and a Class V Landfill is a
commercial facility. Both Class I Landfills and Class V Landfills accept municipal solid
waste, and therefore both Class I Landfills and Class V Landfills require a liner. Further,
the design standards for a Class V Landfill are no more stringent merely because it is a
commercial facility. Utah Admin. Code R315-301-2(7); Utah Admin. Code R315-301-
2(11); Utah Admin. Code R315-303-3(3).
2.2.15 Liners – Board Authority to Pass Rules (RNI)
Comment: In the alternative to requiring liners, and only if the Board will not mandate liners
or hold the hearing called for by 19-6-106, and without waiving the above comments, the
Board should at minimum make liners the presumptive requirement and set forth the
showings an operator would need to make to obtain an exception from the presumptive
liner requirement. Basically, flip the presumption that a liner is only required if certain
conditions are met, to a presumption that liners are required, unless conditions are met.
This is consistent with DOGM’s rules which have required liners for landfarms under
UAC R649-9-5. DOGM has stringent requirements that have to be met before an
exception to liners is allowed, and only if the applicant meets stringent hydraulic
conductivity technical requirements.
Response: Please refer to DWMRC’s response to IWM’s comments, specifically its response
under Sections 2.2.3 and 2.2.9 of this response document.
2.2.16 Liners – Board Authority to Pass Rules (RNI)
Comment: In its response to the informal rulemaking, DWMRC argued that Utah Code 19-6-
106 precluded the Board from requiring liners because that would make Utah’s rules
more stringent than federal rules. However, 19-6-106 is only triggered where the EPA
has “corresponding federal regulations which address the same circumstances.” 19-6-
106(1). As DWMRC points out, EPA does not have rules directly applicable to E&P
landfills, so there are no “corresponding regulations which address the same
circumstances.” Moreover, even if 19-6-106 were triggered, the Board should require
liners because they are necessary to be “adequate to protect public health and the
environment of the state.” 19-6-106(2). If the Board believes 19-6-106 applies, then the
Board should hold the hearing called for by 19-6-106(2) and allow the technical evidence
to be presented and make the findings required under 19-6-106(2) to adopt the liner
requirement.
Response: Please refer to DWMRC’s response to IWM’s comments, specifically its response
under Sections 2.2.7 and 2.2.8 of this response document.
2.2.17 Liners – DOGM Requirements
Comment: It is important to note that the Utah Division of Oil, Gas & Mining (DOGM)
determined in 2013 that solids treated in landfarms should demonstrate liner equivalence
as outlined in R649-9. Not requiring new or expanding landfills under R315-321 to
demonstrate liner equivalence is reverting backward more than a decade in state
environmental standards. The generators of E&P waste have not changed and E&P waste
in a Class VII landfill is intended for permanent disposal and not remediation.
Response: The liner requirements found in Rule R649-9 are for evaporation ponds, for the
management of E&P high liquid waste. Rule R649-9 does not require liners or liner
equivalents for landfarms. Similarly, the management of E&P high liquid waste in solid
waste surface impoundments, as found in Rule R315-322, requires that certain liner
requirements are met, and the requirements for disposal of E&P waste containing no free
liquids into Class VII landfills, as found in Rule R315-321, do not require liners.
2.2.18 Liners – Landfill vs. Surface Impoundment
Comment: It is inconsistent to have different liner requirements for surface impoundments
and landfills as they take waste from the same sources, the only difference is the liquid
content. Assuming that the liquid content in a waste in a landfill will be low is a bad
assumption based on our decade of experience working with these types of landfills.
Response: Please see Section 2.2.7 in this response document.
2.3 Extreme Depth to Groundwater
Comment: There needs to be a specific depth assigned to “extreme depth to groundwater” as
that definition is relative, unclear, and debatable. Also, it should be stated that a “natural
impermeable barrier” must be proved to be impermeable via chemical and physical
property testing and must be of sufficient thickness as determined by a Professional
Geologist, and should be very specifically sufficient thickness as determined by a
Professional Geologist, and should be very specifically insufficient to determine a natural
impermeable barrier is able to prevent groundwater impacts from a facility. This also
applies to the Solid Waste Surface Impoundment Standards (R315-322).
Response: The term “extreme depth to groundwater” is undefined because an owner or
operator must make such a demonstration using technical analysis unique to the facility.
The Director has discretion to make a determination of an “extreme depth to
groundwater” based on evaluation of the technical analysis provided by the owner or
operator and other site-specific characteristics. For reference, Subsections R315-302-
1(2)(e) and R315-308-1(3) provide further detail and should be considered when
demonstrating that a location has an “extreme depth to groundwater.”
2.4 Engineering Reports and Plans
Comment: R315-310 states the facility must provide various topographic, geologic, and
hydrological data. It should be stated that all geological and hydrological data be certified
and collected under the direction of a Professional Geologist, as many applicants tend to
use general drilling logs obtained from unqualified personnel to determine that their
facility has an “impermeable natural barrier” without any other testing of the materials. It
is typical for drillers to provide insufficient lithological logs for borings. Additionally, a
Class VII facility is not required to provide engineering plans, reports, etc. It is Wasatch’s
opinion that Class VII facilities should also have to provide stamped engineering plans
and reports as described in R315-310-4(c).
Response: When geological or hydrogeological data are required, it is in the form of a
geohydrological assessment as detailed in R314-310-4(2)(b). By nature of the strict
requirements of a geohydrological assessment, a professional geologist would be
involved with the collection of the data. Subsection R315-310-4(2)(c) requires “a permit
application for a...Class VII landfill or solid waste surface impoundment that accepts
hazardous waste from a very small quantity generator shall contain an engineering report,
plans, specifications, and calculations that address...”
2.5 Location Standards - Groundwater
Comment: Rule R315-303-2 specifies that the owner or operator of a disposal facility shall
not contaminate the groundwater unlaying a facility. The presence of groundwater at the
facility must be investigated as part of the permit process and is required in the Utah code
R315-302-1 (2) (e). An operator’s responsibility to not contaminate groundwater is
primarily done by meeting landfill liner design requirements that are also provided in
Utah code R315-303-3. We are concerned that the personnel at the DWMRC are
suggesting that Class VII landfills may be permitted without fully investigating the
presence of groundwater and suggesting that liners are not required for a Class VII
landfill.
Response: Utah Admin. Code R315-321-2 directs the reader to Section R315-303-2 where
performance standards are found for all regulated solid waste facilities. Performance
standards broadly describe protections that the owner and operator of a regulated
operation must provide, and intentionally do not provide methods to achieve the
standards. Performance standards may be achieved through a combination of location
standards, design standards, and operation standards, for which minimum requirements
are provided in the regulations. Additionally, an owner and operator may exceed the
minimum standards and may evaluate performance at any given time to prevent
contamination that may lead to expensive remediation. When performance standards are
not met, an owner and operator may be required to conduct an environmental assessment
and take corrective actions to remediate any contamination in accordance with
Subsection R315-301-6(2), which says, “Any contamination of the groundwater, surface
water, air, or soil that results from the management of solid waste which presents a threat
to human health or the environment shall be remediated through appropriate corrective
action.”
2.6 Transfer of Waste to Surface Impoundments
Comment: Can water from the landfill be moved into surface impoundments?
Response: Leachate collected from Class VII landfill cells, and run-off precipitation from a
Class VII landfill cell may be transferred to a solid waste surface impoundment that is
permitted to receive it.
2.7 Unlevel Playing Field
Comment: When IWM designed and constructed its IWM Landfill and its Pinnacle Fuels
Landfill, because of DWMRC’s direction, industry practice, and the other factors
addressed above, IWM included a liner. Under the Proposed E&P Landfill Rule,
competitors would be able to construct new or expanded landfills without having to incur
those same significant costs of designing, constructing and maintaining liners, thus
penalizing IWM and other responsible landfill operators who have complied with
DWMRC’s directions and industry practice, and creating an unfair economic advantage
for operators of new or expanded landfills for which DWMRC would not require a liner
and which would ignore industry practice. Under these circumstances, the Draft E&P
Rule would deprive those operators who have complied with DWMRC direction and
industry practice of a level playing field.
Response: As discussed in Section 2.2.9 of this response document, circumstances of
statutory authority and operational history suggest that liners were appropriate at the time
permits for E&P waste landfills were issued by DWMRC. The requirements found in
Rule R315-321 provide increased protective measures through defined location standards
and closure practices that did not exist under the provisions of Rule R649-9. The
requirements of Rule R315-321 will not allow the receipt of VSQG waste without
groundwater monitoring wells, and requires development of run-on and run-off controls,
establishment of financial assurance mechanisms for closure and post-closure under
different provisions that are more protective of the environment than landfarming
practices. Finally, they will be required to follow closure and post-closure monitoring to
ensure protectiveness of the closure cap and ensure that native vegetation will flourish on
the closed landfill cells.
2.8 Arbitrary and Capricious Agency Action.
Comment: Under the Utah Administrative Procedures Act, a person or entity is entitled to
judicial relief if it “has been substantially prejudiced” by any of the following:
(a) the agency action, or the statute or rule on which the agency action is based, is
unconstitutional on its face or as applied; (b) the agency has acted beyond the
jurisdiction conferred by any statute; (c) the agency has not decided all of the issues
requiring resolution; (d) the agency has erroneously interpreted or applied the law;
(e) the agency has engaged in an unlawful procedure or decision-making process, or
has failed to follow prescribed procedure; (f) the persons taking the agency action
were illegally constituted as a decision-making body or were subject to
disqualification; (g) the agency action is based upon a determination of fact, made
or implied by the agency, that is not supported by substantial evidence when viewed
in light of the whole record before the court; (h) the agency action is: (i) an abuse of
the discretion delegated to the agency by statute; (ii) contrary to a rule of the
agency; (iii) contrary to the agency's prior practice, unless the agency justifies the
inconsistency by giving facts and reasons that demonstrate a fair and rational basis
for the inconsistency; or (iv) otherwise arbitrary or capricious.
Utah Code Ann. §§ 63G-4-403(4). Based on DWMRC’s past liner-related direction to
IWM and other solid waste landfill operators, and the other reasons addressed above, IWM
believes that DWMRC’s approval and implementation of the Proposed E&P Landfill Rule
as-is would constitute, among other things, action “based upon a determination of fact...that
is not supported by substantial evidence…,” an “abuse of discretion,” “contrary to the
agency’s prior practice,” and “otherwise arbitrary or capricious.”
Response: IWM suggests that DWMRC’s approval and implementation of the Proposed E&P
Waste Landfill Rules would be an arbitrary and capricious agency action under the Utah
Administrative Procedures Act (UAPA). For the reasons stated in this response
document, there is no basis to conclude that the Proposed E&P Waste Landfill Rules
would be arbitrary and capricious. In any event, the Utah Administrative Rulemaking Act
governs judicial review of administrative rules, including venue, exhaustion of
administrative remedies, pleading standards, standard of review, and the relief to be
granted. Utah Code § 63G-3-601 et seq. UAPA does not govern judicial review of
administrative rules. Utah Code § 63G-4-102(2)(a) (providing that UAPA does not
govern “the procedure for making agency rules, or judicial review of the procedure or
rules.”). Accordingly, the Director questions the applicability of UAPA’s arbitrary and
capricious standard to the Board’s adoption of the Proposed E&P Waste Landfill Rules
and Division’s implementation of such rules.
3. Solid Waste Surface Impoundment Comments
3.1 Applicability Reference Needed in Rule R315-303
Comment: R315-322-4(1) states that solid waste surface impoundments shall meet the
standards for performance as specified in R315-303-2. However, DWMRC states in
their “Response to Comments” document that “DMWRC is proposing to clarify the
applicability of Rule R315-303 to Class VII landfills by adjusting Section R315-303-
1 to say, “The standards of Rule R315-303 apply to: (4) Class VII Landfills as
specified in Rule proposed R315-321.” DWMRC’s proposed clarification to R315-
303-1 appears to need to be expanded to cover solid waste surface impoundments in
addition to Class VII landfills.
Response: Utah Admin. Code R315-322 specifies that certain requirements of Sections
R315-303-2, R315-303-3, and R315-303-4 apply to solid waste surface
impoundments. The absence of a reference to surface impoundments, or to Rule
R315-322 in the applicability statement in Section R315-303-1 does not impact the
soundness of either rule. The applicability statement found in Section R315-303-1
may be addressed in a future rulemaking for clarity.
3.2 Groundwater Monitoring and Leak Detection
3.2.1 Alternatives and Waivers for Groundwater Monitoring
Comment: At a minimum, this rule [R315-322] should call for a leak detection system of
each impoundment if waiver is granted. We would like to see the DWMRC have a
more aggressive approach to the protection of groundwater and prevent a
contamination plume of impoundment leachate in the event of a compromised liner.
It may be more appropriate to require all impoundments have downgradient
monitoring wells constructed in a way to identify problems with the liner and not
allow exemption of groundwater monitoring.
Similar Comment: Due to the liquid nature of the waste and the potential that liquids will
accumulate in the impoundment it is possible that liquids could be found in the
subsurface if the liners are compromised. If an exemption is approved in part (i) at the
time of permitting and no monitoring is required a leak will not be detected unless a
leak detection system is in place or down gradient wells intercept liquid from the
leak. Having a waiver does not make sense if there is no means to identify a leak in
the future.
Response: An unqualified exemption to groundwater monitoring is not provided in the
rules. Regarding groundwater monitoring alternatives and waivers, Subsection R315-
302-1(2)(e)(vi) provides the Director the authority to “approve, on a site specific
basis, an alternative groundwater monitoring system at the facility or…wave the
groundwater monitoring requirement.”
Under the alternative monitoring option, an owner or operator may propose the
alternative monitoring system. This allows the Director to consider an alternative
groundwater monitoring system that has sampling capability, and a sampling regime
or a detection trigger as part of the monitoring system. Under the waiver option, the
Director may grant a groundwater monitoring waiver if the owner or operator
demonstrates, according to Subsection R315-308-1(3), that there is no potential for
groundwater contamination during the active life and post-closure care period of the
facility. This demonstration requires significant knowledge of the waste
characteristics, degradation processes, and modeling of contaminant fate and
transport. Importantly, neither a groundwater monitoring alternative, nor a
groundwater monitoring waiver, relieve an owner or operator from the responsibility
to take corrective action if groundwater is contaminated.
3.2.2 Leak Detection Waiver at Unloading Structures
Comment: R315-322-5(3)(c) states “Unloading structures shall be designed with a leak
detection system unless determined unnecessary by the Director.” Either the reasons
to determine a leak detection system is not required should be stated specifically, or it
is Wasatch’s opinion that a leak detection system should be mandatory to prevent
adverse effects to human health or the environment.
Response: See Section 1 “Director Discretion” of this response document.
3.2.3 Electrically Conductive Geofabric
Comment: The rule does not mention that the construction of the collection system for leak
detection system should include an electrically conductive geofabric or similar material
between synthetic liners to allow for a liner integrity survey.
Response: The dual liner requirements drafted for surface impoundments are based on
best available technology and include the use of leak detection risers and leak
detection surveys. Upon discovery of a leak, a liner integrity survey may assist an
owner or operator find and repair leaks quickly, and the installation of an electrically
conductive geofabric between liners may be useful. This construction option is
available to owners or operators, but the DWMRC does not prescribe this in the rules.
3.2.4 Liner Integrity Surveys
Comment: The rule does not mention that the construction of the collection system for leak
detection system should include an electrically conductive geofabric or similar material
between synthetic liners to allow for a liner integrity survey.
Response: The dual liner requirements for surface impoundments using leak detection for
groundwater monitoring purposes, are based on best available technologies and include
the use of leak detection risers and leak detection surveys. Upon discovery of a leak, a
liner integrity survey may assist an owner or operator find and repair leaks quickly, and
the installation of an electrically conductive geofabric between liners may be useful. This
construction option is available to owners or operators, but the DWMRC does not
prescribe this in the rules.
3.2.5 Combined Leak Detection and Groundwater Monitoring
Comment: Proposed rule R315-322-5 (10)(i) and (12) has guidance on the use of a Leak
Detection System. It is in GeoStrata’s experience that leak detection systems are not a
reliable measure of problems with liner systems. Problems with leak detection
systems have often been remedied by construction of monitoring wells downgradient
from the impoundment. We would not recommend that leak detections system be the
only means to identifying problems with the liner or in place of a groundwater
monitoring system.
Similar Comment Adds: It is our professional opinion that both groundwater monitoring
and leak detection are necessary to protect groundwater and both should be required.
Response: The leak detection standards for design found in Subsection R315-322-5(13)
include: a drainage and collection system placed between the upper primary and
lower secondary liners, sloped to facilitate the earliest possible detection of a leak;
risers large enough in diameter to allow for visual observation and sampling of any
fluid, and extend to the lowest elevation of the lower secondary liner of the solid
waste surface impoundment; piping capable of withstanding destruction resulting
from contact with waste, structural loading from stresses and disturbances from
overlying waste and cover materials, equipment operation, expansion or contraction,
and facilitate clean-out maintenance; and leak detection monitoring performed with
no greater than five days between monitoring surveys, and on each day that waste is
received in the impoundment. If leak detection systems are designed, maintained, and
operated according to these requirements, a leak will likely be detected sooner by a
leak detection system than in downgradient monitoring wells.
3.2.6 Maximum Allowable Leak Rates
Comment: R315-322-5(10) should set maximum allowable leakage rate limits for solid
waste surface impoundments that choose to utilize leak detection for protection of
groundwater.
Similar Comment: Ponds and impoundments that have HDPE lining systems that meet
industry construction standards will still have leaks. Other regulatory agencies have
used allowable leakage rates for HDPE liners to help identify problems with liners.
Will the DWMRC have an allowable leakage rate to delineate when corrective
actions will need to be taken?
Response: Maximum allowable leakage rates are a technical issue that should be
addressed on a site-specific basis rather than specified by rule.
3.2.7 Unsealed Liners
Comment: Most of the existing evaporation ponds in the Uinta Basin were constructed
with a primary 60 ml liner and a natural clay secondary liner. The primary and
secondary liners in cells constructed in this manner are not sealed together and can
have groundwater water between the liners in areas of shallow groundwater. As a
result, differentiating the source of water in a leak detection system can be difficult.
What guidance can the DWMRC provide for impoundments that have this type of
construction?
Response: The DWMRC will treat all liquid found in a leak detection system as a leak
until evidence suggests otherwise. The owner or operator will be responsible for
providing evidence that the water is not a leak that requires repair. A comparison of
the electrical conductivity of liquid in the surface impoundment to the electrical
conductivity of liquid in the leak detection monitor will generally make this evident.
3.3 Hydrocarbon Accumulation on Surface Impoundments
Comment: In the proposed rule for Standards of Operation R315-322-6 (4)(a) it states:
“(a) Hydrocarbon accumulation, other than de minimis quantities, on a Class VII
solid waste surface impoundment is prohibited. Any such accumulation shall be
removed within 24 hours of the time accumulation began.” In order to make sure that
operators and regulators have the same expectation, a clearer definition should be
considered.
Similar Comments add: Please define clearly what would not be considered de minimis, as
that term is likely to be used to suit an individual facility’s needs.
Division rules should provide an explicit statutory definition of what constitutes
quantities that exceed the “de minimis” standard, e.g. a specified depth in fractions of
an inch, accumulations exceeding a specified surface area, etc.
Response: Any amount of hydrocarbons on a surface impoundment increases risk to
birds and other wildlife, and increases emissions of volatile organic compounds.
Although it would be difficult to operate in such a way that hydrocarbons are never
observed, a prescriptive regulatory standard would require owners or operators to
frequently measure hydrocarbons on surface impoundments, possibly multiple times
each day. The use of the term “de minimis” meaning lacking significance, trifling,
minimal, or of little importance, is preferred over a specified, measurable amount. For
illustration purposes, a minimal sheen on an area surface impoundment may be de
minimis, but a sheen that covers the whole surface impoundment may not be
considered de minimis.
3.4 Overspray Control
Comment: In the proposed rule for Standards of Operation R315-322-6(5) it states: “(5)
overspray including foam, from sprinklers, wind, or enhanced evaporation systems,
outside of lined areas shall be corrected and cleaned up immediately.” The Utah
Division of Oil Gas and Mining (DOGM) currently limits wind speed during usage of
enhanced evaporations systems. Will there be any wind speed restrictions for using
enhanced evaporation systems?
Similar Comment Adds: R315-322-6(5)(a) should set rules to prevent overspray
contamination and not just require overspray contamination to be cleaned up, e.g.
wind speed limits for use of sprinklers and/or enhanced evaporation, minimum
setbacks from surface water, roads, or property boundaries, etc.
Response: The rules proposed to the Board in Subsection R315-322-5(6) require that
“Enhanced evaporation systems shall be located no closer than 100 feet from a
facility’s exterior boundary.” Subsection R315-322-6(5)(a) states "Operation of
enhanced evaporation systems is prohibited when wind speeds at the unit are equal to
or greater than 15 mph." Further, Subsection R315-322-3(1)(b) states "For solid
waste surface impoundments that use enhanced evaporation systems, a plan to control
overspray, including corrective actions to cleanup waste shall be included in the plan
of operation."
3.5 Protection of Waterfowl and Other Wildlife Receptors
Comment: Per R315-322-4(2), Solid Waste Surface Impoundment facilities are required
to “plan for and implement appropriate measures to protect waterfowl and other
wildlife receptors” but no “appropriate measures” are explicitly required except
fencing. Requirements for “flagging or netting to deter entry by birds and waterfowl”
are at the discretion of the director. Flagging and/or netting should be a minimum
statutory requirement for the protection of birds and waterfowl. Further, the fencing
requirement should explicitly require wildlife-proof fencing.
Response: All entities in Utah are subject to wildlife protection laws, such as the
Endangered Species Act, Migratory Bird Treaty Act, Bald and Golden Eagle
Protection Act, and applicable State laws requiring wildlife protection. The proposed
Subsection R315-322-4 generally addresses solid waste surface impoundments and is
not specific to E&P derived liquids. Requiring the installation, monitoring, and
maintenance of specific wildlife and livestock deterrents may negate other alternative
efforts utilized by industry. Such deterrents may include avian predator sound
devices, abrupt noise producing devices, such as propane cannons, or dedicated onsite
personnel trained to utilize non-lethal deterrents such as shotgun blanks, lasers, or a
licensed falconer. Additionally, wildlife-proof fencing is a broad category and may
also include the installation of barriers that deter small mammals, reptiles, or
amphibians that are subject to Federal or State protection. Each surface impoundment
will have a unique set of local conditions, including migratory bird flyway, elevation,
proximity to anthropogenic influences, habitat conditions suitable for particular
species, etc. Such local conditions may make certain deterrents more effective than
others. DWMRC encourages owners and operators to account for these unique
conditions when seeking to comply with applicable wildlife protection laws.
3.6 Size Limits
Comment: In the proposed rule for Standards for Design R315-322-5(1) it states: “(1)
Surface impoundments shall be designed for 55 acre-feet of water or less, unless
otherwise approved by the director.” The statement at the end “unless otherwise
approved by the director” leaves the rule impoundment without the indication of how
size of impoundment should be limited. Phrases of this type through the proposed
rules and existing rules should be carefully evaluated and have limitations if the
director will allow for exceptions to a rule. It is also unclear whether this rule applies
to only liquid waste. Further clarification on the size of an impoundment would be
helpful for applicants.
Similar Comment adds: It is concerning that the director can approve larger impoundments
with no statutory maximum upper limit. Further, it is our professional opinion that
R315-322-5(1) should also specify a maximum surface area in addition to a
maximum volumetric capacity.
Response: See Section 1 “Director Discretion” of this response document.
3.7 Surface Impoundment Liner Options
Comment: Wasatch concurs with the Standard Design specifications; however, a double
synthetic liner would be more appropriate given that some E&P waste (KCL [potassium
chloride]-based muds) will degrade a clay's ability to remain impermeable to the
specification stated. Given this, it is Wasatch’s opinion that clay liners or natural barriers
of clay are not appropriate as an equivalent or alternative liner. Wasatch believes that to
comply with R315-303-2 all facilities receiving E&P waste should be required to use
synthetic double liners with an interstitial leak detection system in place. If clay liners are
to be considered, it is Wasatch’s opinion that robust physical property testing be
completed and certified under the direction of a Professional Engineer.
Similar Comment: DWMRC cites several references indicating that potassium chloride is
added to well drilling fluids to reduce clay blocking, from which DWMRC concludes that
potassium chloride-based drill mud “will not have a negative effect on clay-lined landfill
cells.” However, the inapt references DWMRC cites are specific to the utilization of
potassium chloride under specific and tightly controlled conditions. It is a well-
established principle in soil science that potassium and sodium cause and contribute to
dispersion of clay soils, leading to an increase in hydraulic conductivity and the potential
for tunnel erosion. In addition, data presented in the Terracon Limited Site Investigation
Report indicates that multiple samples of E&P wastes accepted at the Integrated Water
Management facility reported exchangeable sodium percentage (ESP) and sodium
adsorption ratio (SAR) results that exceeded Utah Department of Natural Resources,
Division of Oil, Gas and Mining cleanup levels for oil and gas E&P related sites by up to
several fold. Because sodium contributes to clay dispersion more strongly than
potassium, these high ESP and SAR wastes have potential to negatively affect the
hydraulic conductivity of both engineered compacted clay liners and native clays that
may be considered as alternatives to synthetic liners.
Response: Subsection R315-303-3(4) provides three liner design options, including standard
design, equivalent design, or alternative design. The standard design found in Subsection
R315-303-3(4)(a) requires a composite liner system and a leachate collection system. The
equivalent design found in Subsection R315-303-3(4)(b) requires the owner and operator
to demonstrate that the equivalent design will be as protective as the standard design,
including hydrogeologic characteristics, climatic factors, and volume and physical and
chemical characteristics of the leachate generated by the waste accepted at the facility.
The alternative design found in R315-303-3(4)(c) similarly requires demonstrations by
the applicant, including the same as required for equivalent design, plus predictions of
contaminant fate and transport. The DWMRC maintains that the liner requirements of
Subsection R315-303-3(4), as applied to solid waste surface impoundments under
proposed Section R315-322-5, are protective of human health and the environment. See
also Section 6.1 of this response document.
3.8 Stormwater Retention Ponds
Comment: R315-322 should not apply to a typical stormwater retention pond at a solid
waste landfill facility. When considering the risk of contaminated runoff from a solid
waste facility, the risk is relatively low, especially in an arid climate. First, the active
waste disposal areas at any given time are very small relative to the overall size of the
facility. For example, at Bountiful’s facility the current area contributing to runoff to
the existing pond is 60 acres. Of this, the active landfilling area is approximately 0.5
acres. This amounts to less than 1% of the contributing area. Second, the waste is
generally relatively dry such that precipitation falling on the waste, even with a long
duration storm, is absorbed and does not run off. Third, the waste in the active area,
even if compacted, has many non-uniform depressions allowing for a significant
amount of interception and small-pocket storage of the precipitation. Additionally,
according to information provided to the Division of Waste Management and
Radiation Control Board, R315-322 is intended to regulate the management of liquid
waste. However, stormwater runoff is not generally liquid waste, although
stormwater may carry impurities. Stormwater from any developed area including
residential homes, parks, streets, etc. is likely to carry impurities. Substances such as
vehicle fluid drips on streets, fertilizer particles on sidewalks, pet waste, litter, etc.
can all impact stormwater but does not mean stormwater is liquid waste. Practices to
minimize pollution of stormwater can be effective, even at a solid waste landfill
facility, without the need to handle the runoff as liquid waste. Furthermore, industrial
facilities including solid waste landfills are regulated by the State of Utah for
stormwater discharges. Such facilities are required to prepare a stormwater pollution
prevention plan, implement pollution prevention practices, perform stormwater
inspections, and monitor stormwater discharges.
The definition of “surface impoundment” as found in R315-301-2 “means a facility
or part of a facility which is a natural topographic depression, human made
excavation, or diked area formed primarily of earthen materials, although it may be
lined with synthetic materials, which is designed to hold an accumulation of liquid
waste or waste containing free liquids, and which is not an injection well. Examples
of surface impoundments are holding, storage, settling, and aeration pits, ponds, and
lagoons” (emphasis added). Although a retention pond at a solid waste landfill could
receive runoff that has come in contact with waste, litter, etc., the main purpose of the
retention pond is to manage stormwater runoff, not dispose of liquid or other waste.
As aforementioned, stormwater may carry impurities yet does not necessarily mean
that the stormwater is contaminated or liquid waste.
The requirements and conditions set out in the proposed rule R315-322 mirror the
requirements of waste disposal and waste management. These many requirements
include the following:
● Location Standards
● Plan of Operation Requirements
● Recordkeeping
● Reporting
● Standards of Performance
● Limits on levees
● Control of run-on and run-off
● Groundwater protection (groundwater monitoring and leak detection)
● Minimum Freeboard
● Financial Assurance
These requirements are justifiable when applied to a waste disposal area but very
excessive when applied to a stormwater retention pond.
Proposed R315-322-5(3)(b) requires that the vertical height of the levees shall not
exceed 25% of the total vertical depth of the surface impoundment. Also, R315-
322(6)(2) requires a minimum of three feet of freeboard. These requirements may
make sense for impoundment of liquid waste disposal but do not make sense if
applied to stormwater retention where the pond would be designed to hold the
capacity of a particular storm scenario but available freeboard would be dependent on
the weather and drainage conditions. Furthermore, the requirements are far too
conservative if applied to stormwater retention.
The proposed rule (R315-322-5(8) requires the surface impoundment be designed to
control surface water run-off, then refers to the existing rule about collecting and
treating runoff from a 25-year storm. If the rule also applies to stormwater retention
ponds, it would be a circular rule where the retention pond would require itself. This
further suggests that the rule was not intended to address stormwater retention ponds.
Other aspects of the rule that indicate the rule is not intended to apply to stormwater
retention: A stormwater retention pond would not have an unloading structure
(R315-322-5(4). A stormwater retention pond would not normally have any reason to
prevent run on (R315-322-5(8) and R315-303-3(c)), but rather would be intended to
receive run-on
Response: The Division agrees with this assessment and does not expect stormwater
retention ponds at solid waste facilities to be regulated by the requirements of Rule
R315-322. In accordance with Section R315-301-6, any contamination of the
groundwater, surface water, air, or soil resulting from the management of solid waste
which presents a threat to human health or the environment shall be remediated
through appropriate corrective action. If measures performed under a Storm Water
Pollution Prevention Plan or other pollution prevention practices are not effective, the
Director, or other applicable local or state authorities may require further actions.
4. Groundwater Protection – Landfills or Surface Impoundments
4.1 Natural Impermeable Barrier
Comment: “Groundwater Alternative” rules incorporated by reference in R315-302-
1(7)(vi)(A) [sic] should require quantitative confirmation of the presence of a
“natural impermeable barrier” above the groundwater, i.e. collection of a
representative sample and laboratory testing to confirm that the material has a
hydraulic conductivity of <1x10-7 centimeters per second.
Response: Subsection R315-301-2(54) defines permeability, and states that “Soils and
synthetic liners with a permeability for water of 1 x 10^-7 cm/sec or less may be
considered impermeable.” This standard does not conclude that a “natural
impermeable barrier” above groundwater is present but may be considered when used
as part of the necessary technical analysis.
5. Financial Assurance
5.1 Certificates of Deposit
Comment: RNI requests that DWMRC expressly allow Certificates of Deposits (CDs) as
a form of financial assurance. RNI has CDs in place with DOGM. CDs provide the
same level of agency protection as other acceptable forms of financial assurance,
while carrying lower costs for regulated entities than other forms of financial
assurance. Federal agencies, such as BLM, also allow CDs as financial assurance. See
43 C.F.R. § 3809.555(d).
Response: This request is outside the scope of the current proposed rules and would
require additional rulemaking. Further, it is important to understand that a change in
Financial Assurance mechanism options will affect multiple DWMRC programs. The
Director may consider the option of Certificate of Deposits as a Financial Assurance
mechanism at a future date.
6. General
6.1 Flocculation and Dispersion of Clay
Comment: Sodic and saline soils are common in the Uinta Basin, as are high-sodium
subsurface geologic units due to the Uinta Basin’s geologic history as a former paleolake
that experienced multiple hypersaline phases. Thus, native clays that may be considered
as an equivalent or alternative liner may have naturally-occurring dispersive properties
due to naturally high concentrations of sodium. Further, addition of divalent ions (e.g., Ca
2+) to clays with high sodium content can lead to flocculation (i.e., collapse) of the clay
structure, potentially leading to cracking or similar structural changes that may increase
hydraulic conductivity.
Similar Comment adds: Given the established scientific understanding that salts can
significantly impact the impermeability of clay soils, it's crucial to recognize that a clay
liner may not be sufficient for a landfill designed to handle oilfield waste with very high
salt concentrations. The structural changes induced by high salt levels can compromise
the clay's ability to retain water and increase permeability, thereby undermining the
liner's effectiveness in preventing leachate migration, a key factor in safeguarding
groundwater. Therefore, in scenarios involving high-salinity wastes, such as oilfield
waste, it's not just a matter of choice but a necessity to implement additional protective
measures, like synthetic liners, to ensure the environmental safety and integrity of the
landfill containment system.
The above comment continues with a summary of information found in five publications.
Response: The DWMRC’s understanding is that salinity promotes soil flocculation, which
may reduce permeability of soil or clay, while sodicity promotes soil dispersion, which
may increase permeability of soil or clay. An owner or operator who wishes to meet the
alternate design standards for a liner, must meet the requirements of Subsection R315-
303-3(4)(c)(ii), which states:
“The owner or operator shall demonstrate that the ground water quality protection
standard of Subsection R315-303-2(1) can be met. The demonstration shall be
approved by the director, and shall be based upon:
(A) the hydrogeologic characteristics of the facility and the surrounding land;
(B) the climatic factors of the area;
(C) the volume and physical and chemical characteristics of the leachate;
(D) predictions of contaminant fate and transport in the subsurface that maximize
contaminant migration and consider impacts on human health and the environment;
and
(E) predictions of leachate flow from the base of the waste to the uppermost aquifer”
The balance of any possible flocculation or dispersion of clay from the physical and
chemical characteristics of the leachate generated from the waste must be considered to
provide a complete demonstration.
6.2 Location Standards
6.2.1 Location Standards Citation in R315-322
Comment: The proposed Rule R315-322-2(3)(a) refers to R315-322-3(3)(b) which I
could not find. There appears to be a mistake in this citation.
Response: Thank you for identifying this typographical error. We will revise Subsection
R315-322-2(3)(a) as a non-substantive change at a later date as follows:
(a) Except for the standards listed in Subsection[ R315-322-3(3)(b)] R315-322-
2(3)(b), the director may grant an exemption...
6.2.2 Location Standards Exemptions
Comment: R315-321-3(3)(a) and R315-322-2(3)(a) states “the director may grant an
exemption from any location standard of Subsection R315-302-1(2) for a Class VII
Facility, on a site-specific basis if the director determines that the exemption will
cause no adverse impacts to human health or the environment. If an exemption is
granted, the director may require that the facility have more stringent design,
construction, monitoring program, or operational practice to protect human health or
the environment.
This verbiage is too vague and leaves facility applicants open to potential unfair
treatment compared with other facility applicants. The verbiage “will cause no
adverse impacts” seems to be impossible to meet or should be clearly defined. Maybe
be more specific and what adverse impacts would include. The “the director may
require” verbiage is too vague. Maybe state situations that would require more
stringent designs etc.
Response: The quoted text from the citations listed in this comment does not include the
specific standards that may not be exempted as listed in each of the rules. Please see
Section 1 “Directors Discretion” of this response document to understand how rule
exemptions are handled by DWMRC.
7. Waste Characterization
7.1 How to Make a Waste Determination
Comment: DWMRC should specify how E&P waste is to be properly sampled and
analyzed to determine the waste is not hazardous.
Similar Comment adds: [The] draft rules do not appear to provide standards through which
it can be quantitatively determined whether a facility receives VSQG waste and
whether said waste was generated “incidental to oil and gas exploration and
production and related operations” per R315-321-4(5)(b)(iv).facilities.
Response:
● Hazardous waste is identified according to Rule R315-261, “General
Requirements -- Identification and Listing of Hazardous Waste.”
● The process that a generator of a solid waste must follow to determine whether
waste is hazardous is found in Section R315-262-11, “General -- Hazardous
Waste Determination and Recordkeeping.”
● A generator of hazardous waste makes a determination if it is a very small
quantity generator according to the definition found in Subsection R315-260-
10(c)(172).
● The requirements for an owner of a treatment, storage or disposal facility to
obtain a detailed chemical and physical analysis of a representative sample of
the hazardous waste is found in Section R315-264-13, “General Waste
Analysis.”
The DWMRC recommends that the owner and operator of a solid waste facility
request the record of the waste determination and maintain it in the facility's daily
operating record. The daily operating record is required to contain, among other
information, “the weights, in tons, or volumes, in cubic yards, of solid waste received
each day, number of vehicles entering, and if available, the type of wastes received
each day.” Subsection R315-302-2(3)(a)(i). The daily operating record may be an
effective place to maintain hazardous waste determinations as waste is received at the
facility.
7.2 Hazardous Waste from a Very Small Quantity Generator (VSQG)
7.2.1 Disposal from Multiple VSQGs
Comment: For Class VII landfill facilities that explicitly accept VSQG waste, R315-321
places no restrictions on the number of VSQG generators that an individual Class VII
facility can accept VSQG waste from. Thus, a Class VII landfill facility could accept
VSQG waste from many different VSQGs and have no statutory upper limit on the
total amount of VSQG waste that could be accepted.
Response: Per Subsection R315-321-4(4)(b)(iv), a Class VII landfill is limited to
accepting Very Small Quantity Generator (VSQG) waste that is generated incidental
to oil and gas exploration and production and related operations, and cannot receive
VSQG waste from other generation. This, along with other economic and regulatory
limits will help to manage the amount of VSQG that may be received at an individual
landfill or surface impoundment. In addition, this aligns with federal requirements
that do not provide an upper limit on the total amount of VSQG waste that could be
accepted.
7.2.2 VSQG Waste Training
Comment: Per R315-322-3(2)(d), E&P solid waste surface impoundments that do not
receive VSQG hazardous waste are required to “submit details of controls and
employee training programs used to prevent the acceptance of very small quantity
generator waste.” Division rules should specify minimum levels and standards for
“controls and employee training programs” that must be implemented by
owner/operators.
Response: The DWMRC recommends that owners and operators seek out, evaluate, and
enroll in training courses that are commercially available on hazardous waste
management offered by various educators and consulting groups. Additionally, the
DWMRC recommends that owners and operators supplement available training
courses with facility-specific training to ensure specific wastes that arrive at each
facility are understood, handled properly, appropriate documentation is maintained,
and that any facility-specific hazards are addressed.
7.2.3 VSQG Waste Determination
Comment: It is also probable that VSQG waste that is not generated incidental to oil and
gas exploration and production and related operations may nevertheless become
comingled with incidentally- generated VSQG waste and/or exempt E&P waste and
be disposed of at Class VII landfill facilities...Even with appropriate training,
distinguishing non-exempt hazardous waste from exempt E&P waste at the point of
acceptance at a disposal facility may be difficult, if not impossible, since exempt
E&P waste and non-exempt hazardous waste can contain the same chemical
constituents and thus cannot be distinguished even with laboratory analytical data.
Response: Section R315-262-11 requires a generator of solid waste to determine
whether waste is hazardous and to maintain records of each hazardous waste
determination. The DWMRC recommends that the owner and operator of a solid
waste facility request the record of the waste determination and maintain it in the
facility's daily operating record. Waste management facility operators should
comprehend how waste determinations are made in order to appropriately review
records provided by waste generators or waste haulers, and otherwise have a
reasonable understanding of how to recognize waste that cannot be accepted. These
practices can reduce the risk of inadvertent acceptance of hazardous waste.
7.2.4 VSQG Waste Not Incidental to E&P
Comment: DWMRC’s “Response to Comments” states that the “distinction in liner
requirements for E&P waste landfills and solid waste surface impoundments
addresses the type of waste accepted in the respective facilities and the associated
risks.” However, because Class VII landfill facilities are explicitly allowed to accept
VSQG waste in theoretically unlimited quantities (due to no upper limit on mass or
volume), it appears likely, if not inevitable, that under the current proposed Rule,
Class VII landfill facilities will accept non-incidentally-generated VSQG waste, non-
exempt E&P waste, and/or other hazardous waste in non-de minimis quantities. They
will likely also accept exempt E&P waste that demonstrates characteristics of
hazardous waste or contains constituents that would be regulated as hazardous waste
under other circumstances. Thus, DWMRC’s utilization of the presence or absence of
high liquid wastes as the sole criteria for the distinction in liner requirements for
Class VII landfills and solid waste surface impoundments appears to be arbitrary.
Response: Surface impoundments are intentionally constructed to hold liquids and must
meet a liner standard under the Water Quality Act in addition to surface
impoundment requirements for treatment, storage, or disposal of hazardous waste.
For disposal of wastes identified in Subsection R315-321-4(4)(b) into Class VII
landfills, the federal “Disposal Standards for the Receipt of Very Small Quantity
Generator (VSQG) Wastes at Non-Municipal Non-Hazardous Waste Disposal Units,”
found in Subpart B of 40 C.F.R. § 257, have been incorporated into Rule R315-321
and other applicable sections of Rule R315.
The rules require that a waste generator must determine whether a waste stream is
hazardous, and that a waste management facility owner or operator only receives
waste approved for disposal according to requirements of the facility. The rules
prescribe certain location standards found in Subsection R315-302-1(2)(e), run-on
and run-off control found in Subsection R315-303-3(1), closure requirements
including final cover and post-closure care requirements found in Section R315-303-
3, and when hazardous waste is received (from a very small quantity generator),
groundwater monitoring as found in Subsection R315-321-4(3). These measures
provide protections to groundwater that are consistent with the Solid and Hazardous
Waste Act and federal requirements. However, an owner or operator who identifies
other benefits which may result from installing liners, or other engineering and
operational controls, may do so when those measures are not less restrictive than the
rules.
More discussion on liners is provided in responses found in Section 2.2 of this
response document.
8. General Questions
8.1 EPA vs DWMRC Standards
Comment: How do operators reconcile differences in design standards between EPA and
WMRC? Who has primacy?
Response: There are no differences to reconcile. The DWMRC appreciates EPA's letter
and acknowledges that the best practices identified therein are recommended to “help
ensure compliance with the RCRA requirements...depending on site-specific
conditions.” The groundwater monitoring requirements found in 40 C.F.R. Part 257
are applicable only to non-municipal non-hazardous waste disposal units that receive
hazardous waste from a very small quantity generator (see 40 C.F.R. § 257.5(a)(2)),
and coal combustion residuals (CCR) landfills that receive CCR (see 40 C.F.R. §
257.90). The DWMRC has incorporated groundwater monitoring requirements for
facilities that receive hazardous waste from very small quantity generators. The liner
requirements of 40 C.F.R. Part 257 are applicable only to CCR landfills that receive
CCR, as defined by 40 C.F.R. § 257.53. E&P Waste landfills are not authorized to
receive CCR. As further discussed under Section 2.2 of this response document, the
liner requirements under 40 C.F.R. Part 257 are not applicable to E&P waste
landfills.
8.2 Initial Permit
Comment: Does new Class VII refer to newly constructed or for the initial permit?
Similar Comment Adds: Will facilities with existing WMRC permits need permit mods or
new permits if they want to convert an existing DOGM permitted pond to a surface
impoundment?
Response: Some rule requirements are specific to “new and laterally expanding”
facilities and some are specific to “existing” facilities. A “new” facility is one that is
not “existing.” The current definition for “existing” includes all current DWMRC-
permitted solid waste disposal facilities and has been revised to include all solid
waste disposal facilities that had a Division of Oil, Gas, and Mining (DOGM) permit
as of October 1, 2023. See Subsection R315-301-2(23). Next, wherever “lateral
expansion” of an existing facility is used, the requirement applies to the expansion of
a facility beyond the property boundaries outlined in the permit application for the
current permit under which the facility is operating. See Subsection R315-301-2(24).
Unless otherwise specified in the rules, the horizontal expansion or construction of a
cell, module, or unit within the boundaries outlined in the permit application of the
current permit is considered “existing.” See Subsection R315-301-2(43).
E&P waste landfills with existing DWMRC permits that do not have a need to add
waste management units to the existing permit (i.e., are not adding units currently
permitted by DOGM), and are not expanding outside of the current boundaries of
their DWMRC permit, are not required to apply for a new permit as part of the
regulatory shift. E&P waste landfill owners and operators with existing DWMRC
permits will be transitioned to a Class VII landfill permit at the next scheduled
renewal for each existing permit.
8.3 Landfarm Reclamation
Comment: WMRC has stated that landfarms can be reclaimed by covering them in soil
or clay. Is any post closure monitoring required in this process?
Response: DWMRC has not made a statement that landfarms can be reclaimed by
covering them in soil or clay. Rather, DWMRC has stated that landfarm owners and
operators that seek closure under DWMRC requirements at the time of regulatory
transition may apply for a closure and post-closure permit, or they may apply for risk-
based closure.
For owners and operators choosing a closure and post-closure care permit for any
portion of an existing facility, a closure plan must be submitted that meets the
requirements of Subsection R315-321-4(5) , and an application for a post-closure
permit must be submitted according to Section R315-310-10.
Under the requirements of a closure and post-closure permit, no testing of waste to be
covered is required. However, the soil used for final cover must be uncontaminated
soil that never had waste applied to it. The application for a closure and post-closure
care permit will require a post-closure care monitoring plan to meet the applicable
requirements of Subsections R315-302-3(5) and R315-302-3(6).
Risk-based closure will only apply to facilities that have selected this option at the
time of transition from regulation under Rule R649-9 to regulation under Rule R315.
For risk-based closure, all standards are found in Rule R315-101, Cleanup Action and
Risk-Based Closure Standards.
8.4 Removal of Waste from a Landfill
Comment: Can waste be removed from a class 7 landfill and if so what are the cleanup
standards?
Response: The DWMRC does not have a full understanding of what the commenter
means by asking if waste can be removed from a Class VII landfill; or what the
question about associated cleanup means. If waste is removed from a Class VII
landfill, appropriate analysis of the material must be conducted if it will be used as a
product or product substitute, and if it is not to be used as a product or product
substitute, it must still be managed as waste.
8.5 Soil Testing – Background
Comment: What analytes are to be tested when testing background soils?
Response: The proposed rules do not require testing background soil analytes. The
question does not provide enough information to understand what objectives the
commenter might try to achieve by such tests. The commenter may find additional
information by reviewing Rule R315-101, which includes detail on background
analysis under various circumstances.
8.6 Soil Testing – Closure
Comment: Is any soil testing required of both the material in the landfarm and or the soil
cap?
Response: No testing of waste to be covered with a final landfill cover is required.
However, the soil used for final cover must be uncontaminated soil that never had
waste applied to it.
For any facility seeking risk-based closure, a request to use risk-based closure must
be made at the time of transition from regulation under Rule R649-9 to regulation
under Title R315. For risk-based closure, all standards are found in Rule R315-101,
Cleanup Action and Risk-Based Closure Standards.
8.7 Skim Ponds
8.7.1 De minimis Hydrocarbon Accumulation
Comment: Will skim ponds have the same de minimis oil limitation as surface
impoundments?
Response: Yes, the solid waste surface impoundment rule applies to any part of a solid
waste facility that is a natural topographic depression, human-made excavation, or a
diked area designed to hold nonhazardous high liquid waste, leachate, or sludge, to
dispose of, reduce the volume of, or otherwise separate or treat the waste. Skim ponds
qualify as solid waste surface impoundments, and proposed Rule R315-322 will
apply. If surface impoundments are used for oil separation, the de minimis
hydrocarbon accumulation standard applies.
8.7.2 Netting
Comment: Will netting be required for skim ponds?
Response: Subsection R315-322-4(3) applies to all surface impoundments, and states,
"The solid waste surface impoundment shall be fenced and maintained to deter access
by livestock and wildlife and, if determined necessary by the director, equipped with
flagging, netting, or other measures, to deter entry by birds and waterfowl."
8.8 Oil Pits Should Have Liners
Comment: Vote NO - Public Comment on proposed rule changes Rules Amended:
R315-301, R315-302, R315-303, R315-304, R315-305, R315-307, R315-308, R315-
310, R315-311, R315-314, R315-315, R315-316, R315-317, and R315-318 and new
Rules Created R315-321 and R315-322. I am writing to express my deep concern
over recent developments regarding the regulation of oil waste pits. After years of
requiring liners in these pits (proof of liner requirement in links below), I am appalled
by the apparent lack of transparency in your recent actions. When I contacted your
office two weeks ago to inquire about the proposed new rule, I was informed that
liners were never required in oil mud pits, and that the new rule would not remove
any existing liner requirements because they allegedly never existed. What you failed
to mention is that you recently reclassified oil mud pits under a different category,
one that conveniently lacks any liner requirement. This reclassification amounts to a
shell game with the public, undermining trust and defying industry standards for
proper storage and remediation. To put this in perspective, in Salt Lake County, you
can't dump oil from any source, including a lawn mower, directly on the ground. Yet,
in Duchesne and Uintah Counties, home to vital wildlife and natural resources, this
proposed rule change would make these areas the official dumping grounds for
massive amounts of oil-contaminated products. This disparity is alarming and unjust.
Furthermore, other states, including large oil-producing states like Texas, require
liners as a default measure to protect the environment. Utah should not be lagging
behind in adopting these essential safeguards. In fact, here are links from your
website to permits for facilities that have clearly been required to have liners to
operate: RNI Bluebell Class IIIb Oil and Gas Exploration and Production Waste
Landfill. RNI Wonsit Exploration and Production Waste Class IIIb Landfill,
Integrated Water Management Class IIIb, Integrated Water Management: Pinnacle
Fuels Oil and Gas Exploration and Production Waste Landfill. Let me be clear: I fully
support the need for clean and affordable energy. However, these regulatory changes
pose significant risks to our environment and the health of Utahns. Allowing
companies to dispose of these materials in unlined pits is likely to result in water
contamination and soil pollution. Such short-sighted decisions could also harm future
energy production by damaging the environment we all rely on. As Utahns
committed to responsible energy development, we understand that it is possible to
balance our energy needs with environmental protection. I urge you to reconsider
these changes and support policies that safeguard both our health and our energy
future. With regards to public input on this important matter, earlier today I spoke
with Mr. Brian Speer, who informed me that the board had received numerous emails
related to the proposed rule changes. However, he stated that only one email from the
public comment would be considered, as it was the "only one of substance." Our team
at Prosperous Utah Communities has been actively engaged in informing the public
and elected officials on critical environmental issues surrounding this rule-making
action. We are aware of hundreds of emails that have been sent to you, all clearly
expressing deep concern about the proposed changes to the storage of drill cuttings
and mud. These comments not only recognize the need for clean and affordable
energy but also view these rule changes as a significant risk to our environment and
public health. We respectfully request that ALL public comments received by the
Division of Environmental Quality and the Waste Management and Radiation
Control Board be thoroughly reviewed and be entered into the public record.
Similar Comment: Our team has been actively engaged in informing the public on critical
environmental issues regarding the following rule making action: Rules Amended:
R315-301, R315-302, R315-303, R315-304, R315-305, R315-307, R315-308, R315-
310, R315-311, R315-314, R315-315, R315-316, R315-317, and R315-318 and new
Rules Created R315-321 and R315-322. I am reaching out to you today to ensure that
the comments from many concerned citizens of Utah, that have been sent to the
correct email address ([e-mail]) but in the body addressed to the
members of the Division of Environmental Quality regarding the above rule changes
and specifically proposed changes to the storage of drill cuttings and mud are being
forwarded to the Waste Management and Radiation Control Board. I am reaching out
to you today to ensure that the comments from many concerned citizens of Utah, that
have been sent to the correct email address ([e-mail]) but in the body
addressed to the members of the Division of Environmental Quality regarding the
above rule changes and specifically proposed changes to the storage of drill cuttings
and mud are being forwarded to the Waste Management and Radiation Control
Board. Thank you for your attention to this matter. I appreciate your prompt
confirmation.
Similar Comment: Vote NO: Protect our groundwater, protect our soil. Oil pits should
have liners. To the members of the Division of Environmental Quality, I’m writing to
express my deep concern about the proposed changes to the storage of drill cuttings
and mud in our region. While we all support the need for clean and affordable energy,
these changes pose significant risks to our environment and health. Allowing
companies to just dump these materials into pits without liners could lead to water
contamination and soil pollution. These risks are not only short-sighted but could also
harm future energy production by damaging the very environment we rely on. As
Utahns who believe in responsible energy development, we know it’s possible to
balance our energy needs with environmental protection. I urge you to reconsider
these changes and support policies that safeguard both our health and our energy
future.
Similar Comment: Urgent: Stop the Deregulation of Double Lining in Oil Mud Pits. I am
writing as a deeply concerned citizen of Utah to express my strong opposition to the
proposed deregulation of the double lining requirement in oil mud pits. This proposed
change poses a severe risk to the environment, wildlife, and the health and safety of
our communities, particularly in Eastern Utah. The Department is considering a move
that would allow oil companies to bypass the essential double lining of pits where
they store mud, oil, and contaminated water. Deregulating this crucial protection
means that toxic chemicals will inevitably seep into the soil and contaminate our
precious water resources. As you are well aware, most of these oil companies operate
near the Green and Duchesne Rivers. This proximity means that any contamination
from unlined pits would almost certainly lead to pollution of these vital water bodies.
The consequences for our environment, our wildlife, and our families—especially our
children—would be catastrophic. The people of Utah are tired, mad, and deeply
worried about this situation. We rely on you to safeguard our natural resources, not to
endanger them. Our water, our soil, our wildlife, and our children's futures are at
stake. I urge you to reconsider and to maintain the regulation that mandates double
lining for oil mud pits. This is a matter of utmost importance and urgency. Please, do
not put our environment and our health at risk for the sake of deregulation.
Similar Comment: Urgent Request to Maintain Double Lining Regulations for Mud Oil
Pits in Eastern Utah. I am writing to express deep concern regarding the proposed
deregulation of the double lining requirement for mud oil pits in Eastern Utah. This
change poses a significant threat to our water resources, particularly the Green and
Duchesne Rivers, which are vital for both ecological balance and community well-
being. The removal of the double lining could lead to: **Soil and Water
Contamination**: Toxic chemicals from these pits could seep into our soil and water,
affecting not just wildlife but also human health. **Long-term Environmental
Damage**: The potential for irreversible harm to our local ecosystems and economy,
which relies heavily on clean water for agriculture, fishing, and tourism. We urge you
to reconsider this decision and maintain or strengthen the current regulations to:
**Protect Our Water**: Ensure the safety of our drinking water and the health of our
rivers. **Safeguard Public Health**: Prevent exposure to harmful substances that
could lead to serious health issues. Please consider the long-term implications of this
decision. The health of our environment and community should not be compromised
for short-term economic gains. Vote NO: Protect our groundwater, protect our soil.
Oil pits should have liners.
Similar Comment: Water is Life - literally - Vote NO to protect our groundwater - OIL
PITS NEED LINERS. I am mystified how clean water—drinking water and water for
our crops—has become politicized. Even Mitch McConnell vote for the Clean Water
Act. Remember that? Whether clay-bottomed or not ALL pits leach water eventually
and through fissures, contaminates make their way to groundwater. I teach my
grandkids to clean up after themselves. Why shouldn’t these companies have to tend
to the waste from their extractive industry? Line these oil pits will not bankrupt these
companies. Cleaning up contamination will fall on tax payers like it always does.
OTE NO, please.
Similar Comment: Vote NO: Protect our groundwater, Oil pits should have liners.
Regarding the issue of removing liners from oil pit waste sludge ponds…… Are you
eff’in kidding me? Why would you remove water quality protections? I would
venture a guess that lining a toxic sludge pond with barrier material isn’t that
expensive. If you make these changes to sludge pit requirements, you’re gonna look
very compromised! C’mon man, Its in your job title. Protect our “environmental
quality”. Don’t rely on the energy sector’s research to tell you liners are not
necessary. Your responsibility, and their activities, are mutually incompatible. You
gotta keep a firm boot up their @ss, we are counting on YOU to protect us. So, thank
you for protecting us! Region 8 has enough super fund sites to deal with. We don’t
need another Oklahoma-type disaster. And all the rest of this blah, blah blah…. I’m
writing to express my deep concern about the proposed changes to the storage of drill
cuttings and mud in our region. While we all support the need for clean and
affordable energy, these changes pose significant risks to our environment and health.
Allowing companies to just dump these materials into pits without liners could lead
to water contamination and soil pollution. These risks are not only short-sighted but
could also harm future energy production by damaging the very environment we rely
on. I urge you to reconsider these changes and support policies that safeguard both
our health and our energy future.
Similar Comment: Please Vote NO: Oil pits should have liners. I’m writing to express my
concern about the proposed changes to the storage of drill cuttings and mud in our
region. We all support the need for clean and affordable energy, but these changes
pose significant risks to our environment and health. Allowing companies to dump
these materials into pits without liners could lead to water contamination and soil
pollution. These risks are not only short-sighted but could also harm future energy
production by damaging the very environment we rely on. As Utahns who believe in
responsible energy development, we know it’s possible to balance our energy needs
with environmental protection. I urge you to reconsider these changes and support
policies that safeguard both our health and our energy future.
Similar Comment: Vote NO - Public Comment on proposed rule changes Rules Amended:
R315-301, R315-302, R315-303, R315-304, R315-305, R315-307, R315-308, R315-
310, R315-311, R315-314, R315-315, R315-316, R315-317, and R315-318 and new
Rules Created R315-321 and R315-322. I am writing to express my deep concern
over recent developments regarding the regulation of oil waste pits. After years of
requiring liners in these pits (proof of liner requirement in links below), I am appalled
by the apparent lack of transparency in your recent actions. When I contacted your
office two weeks ago to inquire about the proposed new rule, I was informed that
liners were never required in oil mud pits, and that the new rule would not remove
any existing liner requirements because they allegedly never existed. What you failed
to mention is that you recently reclassified oil mud pits under a different category,
one that conveniently lacks any liner requirement. This reclassification amounts to a
shell game with the public, undermining trust and defying industry standards for
proper storage and remediation. To put this in perspective, in Salt Lake County, you
can't dump oil from any source, including a lawn mower, directly on the ground. Yet,
in Duchesne and Uintah Counties, home to vital wildlife and natural resources, this
proposed rule change would make these areas the official dumping grounds for
massive amounts of oil-contaminated products. This disparity is alarming and unjust.
Furthermore, other states, including large oil-producing states like Texas, require
liners as a default measure to protect the environment. Utah should not be lagging
behind in adopting these essential safeguards. In fact, here are links from your
website to permits for facilities that have clearly been required to have liners to
operate: RNI Bluebell Class IIIb Oil and Gas Exploration and Production Waste
Landfill. RNI Wonsit Exploration and Production Waste Class IIIb Landfill,
Integrated Water Management Class IIIb, Integrated Water Management: Pinnacle
Fuels Oil and Gas Exploration and Production Waste Landfill. Let me be clear: I fully
support the need for clean and affordable energy. However, these regulatory changes
pose significant risks to our environment and the health of Utahns. Allowing
companies to dispose of these materials in unlined pits is likely to result in water
contamination and soil pollution. Such short-sighted decisions could also harm future
energy production by damaging the environment we all rely on. As Utahns
committed to responsible energy development, we understand that it is possible to
balance our energy needs with environmental protection. I urge you to reconsider
these changes and support policies that safeguard both our health and our energy
future. With regards to public input on this important matter, earlier today I spoke
with Mr. Brian Speer, who informed me that the board had received numerous emails
related to the proposed rule changes. However, he stated that only one email from the
public comment would be considered, as it was the "only one of substance." Our team
at Prosperous Utah Communities has been actively engaged in informing the public
and elected officials on critical environmental issues surrounding this rule-making
action. We are aware of hundreds of emails that have been sent to you, all clearly
expressing deep concern about the proposed changes to the storage of drill cuttings
and mud. These comments not only recognize the need for clean and affordable
energy but also view these rule changes as a significant risk to our environment and
public health. We respectfully request that ALL public comments received by the
Division of Environmental Quality and the Waste Management and Radiation
Control Board be thoroughly reviewed and be entered into the public record.
Response: The term “pit” or “oil pit” when associated with the disposal of E&P waste is
synonymous with Class VII solid waste surface impoundments defined in proposed
Subsection R315-301-2(75), and regulated chiefly by Rule R315-322. Class VII solid
waste surface impoundments are required to have conservative liner systems per
Subsection R315-322-5(12). Drill cuttings and mud, however, are more likely to be
managed in Class VII landfills unless these wastes contain high liquid wastes. It is
important to understand that landfills may not accept waste containing free liquids or
constituting high liquid waste, and for reasons discussed below and in Section 2.2 of
this response document, do not require liners.
The transfer of regulatory oversight from the Division of Oil, Gas, and Mining, will
not result in a reduction of environmental protections or deregulation. In Utah, oil and
gas exploration, development, and production waste (E&P waste) is primarily
managed in three ways:
1) Class II oil and gas related injection wells may be used for E&P produced water
when it meets requirements, and is regulated by the Division of Oil, Gas, and
Mining. The regulatory oversight of this disposal method is not transferring.

2) E&P waste that meets the standard of containing no free liquids may be disposed
of on land. The Division of Oil, Gas, and Mining has historically permitted
"landfarms" for this purpose, regulated under Utah Administrative Code R649-9.
These requirements do not include liners for landfarms. Landfarms will be
transitioned to the Division of Waste Management and Radiation Control for
regulatory oversight. The proposed Rule R315-321, Class VII Exploration and
Production Waste Landfill Requirements, will be the primary rule under which
these facilities will be regulated. E&P landfills will be required to meet a few
additional regulatory requirements, including but not limited to requirements that
govern the disposal of hazardous waste from a very small quantity generator,
design and management of dewatering or stabilization practices, final closure
using landfill standards, and post-closure care monitoring.

3) Produced water and other similar E&P waste liquids that are not disposed of in
Class II injection wells have historically been disposed of in "evaporation ponds"
as permitted by the Division of Oil, Gas, and Mining, also regulated under Utah
Administrative Code R649-9. These standards require liners for evaporation
ponds. Certain evaporation ponds will be transitioned to the Division of Waste
Management and Radiation Control for regulatory oversight. The proposed Rule
R315-322, Solid Waste Surface Impoundment Requirements will be the primary
rule under which these facilities will be regulated. Surface impoundments will be
required to meet a few additional regulatory requirements, including but not
limited to requirements that govern disposal of hazardous waste from a very small
quantity generator, some small changes to closure standards, and the addition of
post-closure care monitoring.
DWMRC maintains that, unless otherwise determined by the Director, liners are not
required for new or expanding Class VII E&P waste landfill cells under proposed
Rule R315-321. The relevant regulations are outlined under Section 2.2.7 of this
response document.

Management of Exploration,
Development and Production Wastes:
Factors Informing a Decision on the Need for
Regulatory Action

April 2019

United States Environmental Protection Agency
Office of Land and Emergency Management
Office of Resource Conservation and Recovery

Management of Exploration, Development and Production Wastes
Front Matter i

Disclaimer
This document has been prepared by the Office of Resource Conservation and Recovery in the U.S.
Environmental Protection Agency. Any opinions, findings, conclusions, or recommendations do not
change or substitute for any statutory or regulatory provisions. This document does not impose legally
binding requirements, nor does it confer legal rights, impose legal obligations, or implement any
statutory or regulatory provisions. Mention of trade names or commercial products is not intended to
constitute endorsement or recommendation for use.

Management of Exploration, Development and Production Wastes
Front Matter ii

Table of Contents
List of Tables ................................................................................................................................................ v
List of Figures ............................................................................................................................................. vii
Definitions ................................................................................................................................................. viii
1. Introduction ........................................................................................................................................ 1-1
Regulatory History .......................................................................................................................................................... 1-1
Changes within the Industry ....................................................................................................................................... 1-2
Document Purpose and Scope .................................................................................................................................. 1-4
2. Summary of Agency Actions ............................................................................................................. 2-1
1992 Background for NEPA Reviewers ................................................................................................................... 2-1
1992 Review of Operations in Alaskan North Slope ......................................................................................... 2-1
1996-1999 Oil Field Waste Pit Program ................................................................................................................ 2-2
2000 Associated Waste Reports ............................................................................................................................... 2-3
2010 Review of Damage Cases ................................................................................................................................. 2-4
2014 Review of State Regulations ............................................................................................................................ 2-4
2014 Compilation of Best Management Practices ............................................................................................ 2-5
1988-2019 Voluntary Initiatives ................................................................................................................................ 2-5
3. Industry Overview .............................................................................................................................. 3-1
Summary of Site Operations ...................................................................................................................................... 3-1
3.1.1. Well Installation .............................................................................................................................................. 3-1
3.1.2. Well Completion and Production ............................................................................................................ 3-4
3.1.3. Well Maintenance .......................................................................................................................................... 3-6
Oil and Gas Production Rates .................................................................................................................................... 3-6
Waste Generation Rates ............................................................................................................................................. 3-10
Economic Structure ...................................................................................................................................................... 3-11
3.4.1. Revenue ........................................................................................................................................................... 3-12
3.4.2. Employment ................................................................................................................................................... 3-12
3.4.3. Resolution of Available Data ................................................................................................................... 3-13
4. Waste Management ........................................................................................................................... 4-1
Pits ........................................................................................................................................................................................ 4-1
4.1.1. Reserve Pits....................................................................................................................................................... 4-3
4.1.2. Production Pits ................................................................................................................................................ 4-4
4.1.3. Other Pits ........................................................................................................................................................... 4-5
Tanks .................................................................................................................................................................................... 4-5
4.2.1. Closed-Loop Drilling ..................................................................................................................................... 4-6
4.2.2. Production Tanks............................................................................................................................................ 4-6
4.2.3. Modular Large Volume Tanks ................................................................................................................... 4-7
Land Application ............................................................................................................................................................. 4-8

Management of Exploration, Development and Production Wastes
Front Matter iii

Other Offsite Disposal ................................................................................................................................................... 4-9
4.4.1. Landfills .............................................................................................................................................................. 4-9
4.4.2. Other Treatment and Disposal Facilities ............................................................................................. 4-10
Beneficial Use ................................................................................................................................................................. 4-11
5. Waste Characterization ...................................................................................................................... 5-1
Spent Drilling Fluid ......................................................................................................................................................... 5-1
5.1.1. Bulk Concentration ........................................................................................................................................ 5-2
5.1.2. Summary – Spent Drilling Fluids .............................................................................................................. 5-7
Drilling Solids ................................................................................................................................................................... 5-7
5.2.1. Bulk Composition ........................................................................................................................................... 5-8
5.2.2. Leachate ........................................................................................................................................................... 5-16
5.2.3. Volatile Emissions ........................................................................................................................................ 5-17
5.2.4. Summary – Drilling Solids ......................................................................................................................... 5-17
Produced Water ............................................................................................................................................................ 5-17
5.3.1. Bulk Composition ......................................................................................................................................... 5-18
5.3.2. Volatile Emissions ........................................................................................................................................ 5-29
5.3.3. Summary – Produced Water .................................................................................................................... 5-29
Pipe Scale ......................................................................................................................................................................... 5-30
5.4.1. Bulk Content................................................................................................................................................... 5-30
5.4.2. Leachate ........................................................................................................................................................... 5-32
5.4.3. Air Emissions .................................................................................................................................................. 5-33
5.4.4. Summary – Pipe Scale ................................................................................................................................ 5-34
Production Sludge ........................................................................................................................................................ 5-35
5.5.1. Bulk Content................................................................................................................................................... 5-35
5.5.2. Leachate ........................................................................................................................................................... 5-38
5.5.3. Air Emissions .................................................................................................................................................. 5-40
5.5.4. Summary – Production Sludge ............................................................................................................... 5-41
Contaminated Soil and Sediment .......................................................................................................................... 5-41
5.6.1. Bulk Content................................................................................................................................................... 5-42
5.6.2. Leachate ........................................................................................................................................................... 5-44
5.6.3. Air Emissions .................................................................................................................................................. 5-45
5.6.4. Summary – Contaminated Soil and Sediment .................................................................................. 5-45
Conclusions ..................................................................................................................................................................... 5-46
6. State Programs ................................................................................................................................... 6-1
Methodology .................................................................................................................................................................... 6-1
Uncertainties ..................................................................................................................................................................... 6-2
Analysis of Specific Elements Across States ......................................................................................................... 6-4
6.3.1. Waste Management Location Requirements (Siting and Setbacks) .......................................... 6-5
6.3.2. Tank Requirements (Onsite/On-Lease) ................................................................................................. 6-7

Management of Exploration, Development and Production Wastes
Front Matter iv

6.3.3. Pit Construction and Operation Requirements .................................................................................. 6-9
6.3.4. Pit Closure Requirements ......................................................................................................................... 6-14
6.3.5. Spill Notification and Corrective Action .............................................................................................. 6-16
6.3.6. Offsite Landfills ............................................................................................................................................. 6-18
6.3.7. Land Application........................................................................................................................................... 6-20
6.3.8. Beneficial Use ................................................................................................................................................. 6-22
6.3.9. NORM and TENORM .................................................................................................................................. 6-26
Conclusions ..................................................................................................................................................................... 6-28
7. Review of Existing Evaluations .......................................................................................................... 7-1
U.S. Environmental Protection Agency (1987d) .................................................................................................. 7-1
7.1.1. Evaluation Summary ..................................................................................................................................... 7-1
7.1.2. Uncertainties .................................................................................................................................................... 7-2
7.1.3. Findings .............................................................................................................................................................. 7-6
U.S. Department of Energy (1998) ........................................................................................................................... 7-6
7.2.1. Evaluation Summary ..................................................................................................................................... 7-7
7.2.2. Uncertainties .................................................................................................................................................... 7-7
7.2.3. Updated Analysis............................................................................................................................................ 7-8
7.2.4. Findings ............................................................................................................................................................ 7-12
Conclusions ..................................................................................................................................................................... 7-13
8. Damage Cases ..................................................................................................................................... 8-1
Review of Recent Damage Cases ............................................................................................................................. 8-1
8.1.1. Review Criteria ................................................................................................................................................. 8-2
8.1.2. Findings .............................................................................................................................................................. 8-3
Spill Reporting ................................................................................................................................................................. 8-4
State Inspection and Enforcement ........................................................................................................................... 8-6
Conclusions ....................................................................................................................................................................... 8-9
9. Summary and Conclusions ................................................................................................................. 9-1
10. References ....................................................................................................................................... 10-1

Appendix A: Damage Cases
Appendix B: Constituent Database
Appendix C: State Programs

Management of Exploration, Development and Production Wastes
Front Matter v

List of Tables
Table 3-1. Estimated Number of Active Wells in 2016 by State ................................................................................... 3-7
Table 3-2. Estimated Crude Oil and Natural Gas Production in 2016 by State. ..................................................... 3-8
Table 3-3. Change in Industry Statistics, 1985 to 2016 .................................................................................................... 3-9
Table 3-4. Estimated E&P Waste Generation in 2016 ..................................................................................................... 3-11
Table 3-5. NAICS 211: Oil and Gas Extraction – Revenues............................................................................................ 3-12
Table 3-6. Oil and Gas Extraction - Employment in 2016 ............................................................................................. 3-13
Table 4-1. Summary of Pit Sizes in Pennsylvania ................................................................................................................ 4-3
Table 4-2. Number of Active Production Pits in California ............................................................................................. 4-4
Table 4-3. Examples of Disposal Pit Sizes in the Permian Basin ................................................................................. 4-11
Table 5-1. Inorganic Elements in Drilling Fluid (mg/L) ..................................................................................................... 5-2
Table 5-2. Organic Compounds in Drilling Fluid (mg/L) .................................................................................................. 5-4
Table 5-3. Radioisotopes in Spent Drilling Fluid (pCi/L) .................................................................................................. 5-5
Table 5-4. Radioisotopes in Residual Solids from Drilling Fluids (pCi/g) .................................................................. 5-5
Table 5-5. Inorganic Elements in Black Shale (mg/kg) ..................................................................................................... 5-9
Table 5-6. Inorganic Elements in Drilling Solids (mg/kg) .............................................................................................. 5-11
Table 5-7. Organic Compounds in Drilling Solids (mg/kg) ........................................................................................... 5-13
Table 5-8. Radioisotopes in Stabilized Drilling Solids (pCi/g) ..................................................................................... 5-14
Table 5-9. Constituent Levels in TCLP Leachate from Drilling Solids (mg/L) ......................................................... 5-16
Table 5-10. Inorganic Elements in Produced Water (mg/L) ......................................................................................... 5-20
Table 5-11. Comparison of Measured and Modeled Barium Concentrations (mg/L) ........................................ 5-24
Table 5-12. Organic Compounds in Produced Water (mg/L) ...................................................................................... 5-25
Table 5-13. Radioisotopes in Produced Water (pCi/L) ................................................................................................... 5-26
Table 5-14. Comparison of Measured and Modeled Radium-226 Activities (pCi/L) .......................................... 5-29
Table 5-15. Radioisotopes in Scale (pCi/g) ......................................................................................................................... 5-31
Table 5-16. Radon Emanation Fraction from Scale .......................................................................................................... 5-34
Table 5-17. Inorganic Elements in Sludge (mg/kg) ......................................................................................................... 5-36
Table 5-18. Organic Compounds in Sludge (mg/kg) ...................................................................................................... 5-37
Table 5-19. Radioisotopes in Sludge (pCi/g) ...................................................................................................................... 5-38
Table 5-20. Inorganic Elements in TCLP Leachate from Sludge (mg/L) ................................................................... 5-39
Table 5-21. Organic Compounds in TCLP Leachate from Sludge (mg/L) ............................................................... 5-40
Table 5-22. Radon Emanation from Sludge ........................................................................................................................ 5-40
Table 5-23. Barium and Radium in Contaminated Media ............................................................................................. 5-42
Table 5-24. Radon Emanation from Contaminated Media ........................................................................................... 5-45
Table 6-1. Summary of Required Setback Distances in Select States. ....................................................................... 6-6
Table 6-2. Summary of Freeboard Requirements for Pits. ............................................................................................ 6-11
Table 6-3. Summary of Required Fencing and Netting for Pits. ................................................................................. 6-11
Table 6-4. Summary of Required Depth to Groundwater for Pits. ............................................................................ 6-13
Table 6-5. Summary of Pit Closure Requirements. .......................................................................................................... 6-15

Management of Exploration, Development and Production Wastes
Front Matter vi

Table 6-6. Summary of Spill Reporting Requirements in Select States. .................................................................. 6-17
Table 6-7. Summary of Wastes Allowed for Land Application. ................................................................................... 6-20
Table 6-8. Location and Siting Restrictions for Land Application. ............................................................................. 6-21
Table 6-9. Summary of Operational Conditions Required for Land Application. ................................................ 6-22
Table 6-10. Summary of Waste Types Allowed for Beneficial Use. ........................................................................... 6-23
Table 6-11. Summary of Beneficial Use Testing Requirements. ................................................................................. 6-24
Table 6-12. Summary of Restrictions on Placement of Waste Liquids on Roadways. ....................................... 6-25
Table 6-13. Summary of Terminology for Radioactivity ................................................................................................ 6-26
Table 6-14. Ranking of State Oil and Gas Production .................................................................................................... 6-29
Table 6-15. Summary of State Program Regulatory Elements .................................................................................... 6-30
Table 6-16. Most Recent Updates to State Programs .................................................................................................... 6-32
Table 7-1. Comparison of Constituent Data for Produced Water................................................................................ 7-3
Table 7-2. Comparison of Constituent Data for Drilling Fluid ....................................................................................... 7-4
Table 7-3. Comparison of Saturated Zone Partitioning Coefficients (ml/g) ............................................................ 7-6
Table 7-4. Comparison of Inputs for RESRAD Model ....................................................................................................... 7-9
Table 8-1. Summary of Relevant Damage Cases, 2012 – 2018 ..................................................................................... 8-3
Table 8-2. Summary of Reported Spills for Select States, 2014 – 2017 ..................................................................... 8-5
Table 8-3. Summary of State Inspections and Enforcement Actions in 2018 ......................................................... 8-7
Table 8-4. Summary of Inspection and Enforcement Personnel in Selected States, 1987 - 2018 .................. 8-8

Management of Exploration, Development and Production Wastes
Front Matter vii

List of Figures
Figure 1-1: Examples of the Different Types of Oil and Gas Reservoirs and Production Wells. ...................... 1-3
Figure 3-1: Diagram of Standard Well Casing Configurations. ..................................................................................... 3-2
Figure 3-2: Typical Production Operation for Oil, Gas, and Water Separation. ...................................................... 3-5
Figure 3-3: Major Shale Gas and Tight Oil Plays ................................................................................................................. 3-9
Figure 3-4: Comparison of Well Completion and Production Volume, 1997 to 2017. ...................................... 3-10
Figure 4-1: Pits with Visible Liners. ........................................................................................................................................... 4-2
Figure 4-2: Pits with Fencing and Netting. ............................................................................................................................ 4-2
Figure 4-3: Flare Pit. ........................................................................................................................................................................ 4-5
Figure 4-4: Tanks with Secondary Containment. ................................................................................................................ 4-6
Figure 4-5: Modular Large Volume Tanks. ............................................................................................................................ 4-8
Figure 4-6: Land Application of E&P Wastes. ...................................................................................................................... 4-8
Figure 4-7: Treatment and Disposal Facilities. ................................................................................................................... 4-10
Figure 5-1: Relationship Between Barium and TSS in Spent Drilling Fluid ............................................................... 5-3
Figure 5-2: Relationship Between 235U and Excess 226Ra in Residual Solids from Drilling Fluid ....................... 5-6
Figure 5-3: Relationship Between 235U and Excess 226Ra in Stabilized Drill Cuttings .......................................... 5-15
Figure 5-4: Oil and Gas Production Zones in the United States (U.S. EPA, 1987d) ............................................. 5-19
Figure 5-5: Relationships of Chloride with Barium and Strontium. ........................................................................... 5-22
Figure 5-6: Relationship of Bicarbonate and Sulfate with Barium and Strontium. .............................................. 5-23
Figure 5-7: Relationship of Chloride and Bromide with Radium-226. ..................................................................... 5-27
Figure 5-8: Relationships of Radium-226 and Radium-228. ........................................................................................ 5-28
Figure 5-9: Relationship Between Barium and Radium in Contaminated Soil ...................................................... 5-43
Figure 5-10: Relationship Between Barium and Radium in Different Deposited Wastes ................................. 5-43
Figure 7-1: RESRAD Model Results With and Without Radon Exposure ................................................................ 7-12

Management of Exploration, Development and Production Wastes
Front Matter viii

Definitions
Definitions of certain terms drawn from the Report to Congress: Management of Wastes from the
Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy
(U.S. EPA, 1987a,b,c):
Acidize: To treat oil-bearing limestone or other formations, using a chemical reaction with acid, to
increase production. Hydrochloric or other acid is injected into the formation under pressure. The acid
etches the rock, enlarging the pore spaces and passage through which the reservoir fluids flow.
Additive: A substance or compound added in small amounts to a larger volume of another substance to
change some characteristic of the latter. In the oil industry, additives are used in lubricating oil, fuel,
drilling mud, and cement for cementing casing.
Annulus or Annular Space: The space around a pipe in a wellbore, the outer wall of which may be the
wall of either the borehole or the casing.
Blow Out: To suddenly expel oil-well fluids from the borehole with great velocity.
Borehole: The wellbore; the hole made by drilling or boring.
Burn Pit: An earthen pit in which waste oil and other materials are burned.
Casing: Steel pipe placed in an oil or gas well as drilling progresses to prevent the wall of the well from
caving in during drilling and to provide a means of extracting petroleum if the well is productive.
Centralized Brine Disposal Pit: An excavated or above-grade earthen impoundment located away from
the oil or gas operations from which it receives produced fluids (brine). Centralized pits usually receive
fluids from many wells, leases, or fields.
Centralized Combined Mud/Brine Disposal Pit: An -excavated or above-grade earthen impoundment
located away from the oil or gas operations from which it receives produced fluids (brine) and drilling
fluids. Centralized pits usually receive fluids from many wells, leases, or fields.
Centralized Mud Disposal Pit: An excavated or above-grade earthen impoundment located away from
the drilling operations from which it receives drilling muds. Centralized pits usually receive fluids from
many drilling sites.
Centralized Treatment Facility (Mud or Brine): Any facility accepting drilling fluids or produced fluids
for processing. This definition encompasses municipal treatment plants, private treatment facilities, or
publicly owned treatment works for treatment of drilling fluids or produced fluids. These facilities
usually accept a spectrum of wastes from a number of oil, gas, or geothermal sites, or in combination
with wastes from other sources.
Completion Fluid: A special drilling mud used when a well is being completed. It is selected not only
for its ability to control formation pressure, but also for its properties that minimize formation damage.

Management of Exploration, Development and Production Wastes
Front Matter ix

Completion Operations: Work performed in an oil or gas well after the well has been drilled to the
point at which the production string of casing is to be set. This work includes setting the casing,
perforating, artificial stimulation, production testing, and equipping the well for production, all prior
to the commencement of the actual production of oil or gas in paying quantities, or in the case of an
injection or service well, prior to when the well is plugged and abandoned.
Condensate: A light hydrocarbon liquid obtained by condensation of hydrocarbon vapors. It consists
of varying proportions of butane, propane, pentane, and heavier fractions, with little or no ethane or
methane.
Cuttings: The fragments of rock dislodged by the bit and brought to the surface in the drilling mud.
Dehydrate: To remove water from a substance. Dehydration of crude oil is normally accomplished by
emulsion treating with emulsion breakers. The water vapor in natural gas must be removed to meet
pipeline requirements; a typical maximum allowable water vapor content is 7 lb per MMcf.
Desander: A centrifugal device used to remove fine particles of sand from drilling fluid to prevent
abrasion of the pumps. A desander usually operates on the principle of a fast-moving stream of fluid
being put into a whirling motion inside a cone-shaped vessel.
Desiccant: A substance able to remove water from another substance with which it is in contact. It may
be liquid (as triethylene glycol) or solid (as silica gel).
Desilter: A centrifugal device, similar to a desander, used to remove very fine particles, or silt, from
drilling fluid to keep the amount of solids in the fluid to the lowest possible level. The lower the solids
content of the mud is, the faster the rate of penetration.
Drilling Fluid: The circulating fluid (mud) used in the rotary drilling of wells to clean and condition the
hole and to counterbalance formation pressure. A water-based drilling fluid is the conventional drilling
mud in which water is the continuous phase and the suspended medium for solids, whether or not oil
is present. An oil-based drilling fluid has diesel, crude, or some other oil as its continuous phase with
water as the dispersed phase. Drilling fluids are circulated down the drill pipe and back up the hole
between the drill pipe and the walls of the hole, usually to a surface pit. Drilling fluids are used to
lubricate the drill bit, to lift cuttings, to seal off porous zones, and to prevent blowouts. There are two
basic drilling media: muds (liquid) and gases. Each medium comprises a number of general types. The
type of drilling fluid may be further broken down into numerous specific formulations.
Drill Pipe: The heavy seamless tubing used to rotate the bit and circulate the drilling fluid. Joints of
pipe 30 ft long are coupled together by means of tool joints.
Drill String: The column, or string, of drill pipe, not including the drill collars or kelly. Often, however,
the term is loosely applied to include both the drill pipe and drill collars.
Enhanced Oil Recovery (EOR): A method or methods applied to depleted reservoirs to make them
productive once again. After an oil well has reached depletion, a certain amount of oil remains in the
reservoir, which enhanced recovery is targeted to produce. EOR can encompass secondary and tertiary
production.

Management of Exploration, Development and Production Wastes
Front Matter x

Formation: A bed or deposit composed throughout of substantially the same kinds of rock; a lithologic
unit. Each different formation is given a name, frequently as a result of the study of the formation
outcrop at the surface and sometimes based on fossils found in the formation.
Formation Water: The water originally in place in a formation.
Fracturing: A method of stimulating production by increasing the permeability of the producing
formation. Under extremely high hydraulic pressure, a fluid is pumped downward through tubing or
drill pipe and forced into the perforations in the casing. The fluid enters the formation and parts or
fractures it. Sand grains, aluminum pellets, glass beads, or similar materials are carried in suspension by
the fluid into the fractures. These are called propping agents. When the pressure is released at the
surface, the fracturing fluid returns to the well, and the fractures partially close on the propping agents,
leaving channels through which oil flows to the well.
Gas Plant: An installation in which natural gas is processed to prepare it for sale to consumers. A gas
plant separates desirable hydrocarbon components from the impurities in natural gas.
Gathering Line: A pipeline, usually of small diameter, used in gathering crude oil from the oil field to
a point on a main pipeline.
Glycol Dehydrator: A processing unit used to remove all or most of the water from gas. Usually a glycol
unit includes a tower in which the wet gas is put into contact with glycol to remove the water. and a
reboiler, which heats the wet glycol to remove the water from it so the glycol can be recycled.
Heater-treater: A vessel that heats an emulsion and removes water and gas from the oil to raise it to a
quality acceptable for pipeline transmission. A heater-treater is a combination of a heater, free-water
knockout, and oil and gas separator.
Hydraulic Fracturing: The forcing into a formation of liquids under high pressure to open passages for
oil and gas to flow through and into the wellbore.
Hydrocarbons: Organic compounds of hydrogen and carbon, whose densities, boiling points, and
freezing points increase as their molecular weights increase. Although composed of only two elements,
hydrocarbons exist in a variety of compounds because of the strong affinity of the carbon atom for
other atoms and for itself. The smallest molecules of hydrocarbons are gaseous; the largest are solid.
Hydrostatic Head: The pressure exerted by a body of water at rest. The hydrostatic head of fresh water
is 0.433 psi per foot of height. The hydrostatic heads of other liquids may be determined by comparing
their gravities with the gravity of water.
Oil and Gas Separator: An item of production equipment used to separate the liquid components of the
well stream from the gaseous elements. Separators are vertical or horizontal and are cylindrical or
spherical in shape. Separation is accomplished principally by gravity, the heavier liquids falling to the
bottom and the gas rising to the top. A float valve or other liquid-level control regulates the level of oil
in the bottom of the separator.

Management of Exploration, Development and Production Wastes
Front Matter xi

Perforate: To pierce the casing wall and cement to provide holes through which formation fluids may
enter or to provide holes in the casing so that materials may be introduced into the annulus between
the casing and the wall of the borehole. Perforating is accomplished by lowering into the well a
perforating gun, or perforator, that fires electrically detonated bullets or shaped charges from the
surface.
Permeability: A measure of the ease with which fluids can flow through a porous rock.
Pig: A scraping tool that is forced through a pipeline or flow line to clean out accumulations of wax,
scale, and so forth, from the inside walls of a pipe. A cleaning pig. travels. with the flow of product in
the line, cleaning the walls of the pipe with blades or brushes. A batching pig is a cylinder with
neoprene or plastic cups on either end used to separate different products traveling in the same pipeline.
Porosity: The quality or state of possessing pores (as a rock formation). The ratio of the volume of
interstices of a substance to the volume of its mass.
Produced Water: The water (brine) brought up from the hydrocarbon bearing strata during the
extraction of oil and gas. It can include formation water, injection water, and any chemicals added
downhole or during the oil/water separation process.
Propping Agent: A granular substance (as sand grains, walnut shells, or other material) carried in
suspension by the fracturing fluid that serves to keep the cracks open when the fracturing fluid is
withdrawn after a fracture treatment.
Sediment: The matter that settles to the bottom of a liquid; also called tank bottoms, basic sediment,
and so forth.
Separator: A cylindrical or spherical vessel used to isolate the components in mixed streams of fluids.
Shale Shaker: A series of trays with sieves that vibrate to remove cuttings from the circulating fluid in
rotary drilling operations. The size of the openings in the sieve is carefully selected to match the size
of the solids in the drilling fluid and the anticipated size of cuttings. It is also called a shaker.
Stock Tank: A crude oil storage tank.
Surfactant: A substance that affects the properties of the surface of a liquid or solid by concentrating
on the surface layer. The use of surfactants can ensure that the surface of one substance or object is in
thorough contact with the surface of another substance.
Tank Battery: A group of production tanks located in the field that store crude oil.
Weighting Material: A material with a specific gravity greater than that of cement; used to increase the
density of drilling fluids or cement slurries.
Wellbore: A borehole; the hole drilled by the bit. A wellbore may have casing in it or may be open (i.e.,
uncased); or a portion of it may be cased and a portion of it may be open.
Well Completion: The activities and methods necessary to prepare a well for the production of oil and
gas; the method by which a flow line for hydrocarbons is established between the reservoir and the

Management of Exploration, Development and Production Wastes
Front Matter xii

surface. The method of well completion used by the operator depends on the individual characteristics
of the producing formation or formations. These techniques include open-hole completions,
conventional perforated completions, sand-exclusion completions, tubing-less completions, multiple
completions, and miniaturized completions.
Wellhead: The equipment used to maintain surface control of a well including the casinghead, tubing
head, and Christmas tree.
Well Stimulation: Any of several operations used to increase the production of a well.
Workover: One or more of a variety of remedial operations performed on a producing oil well to try to
increase production. Examples of workover operations are deepening, plugging back, pulling and
resetting the liner, squeeze-cementing, and so on.
Workover Fluids: A special drilling mud used to keep a well under control when it is being worked
over. A workover fluid is compounded carefully so it will not cause formation damage.

Management of Exploration, Development and Production Wastes
Section 1: Introduction 1-1

1. Introduction
The United States Environmental Protection Agency (“EPA” or “the Agency”) was granted authority
to establish a national framework for solid waste management under the Resource Conservation and
Recovery Act of 1976 (RCRA; Public Law 94-580). The intent of this law is to conserve energy and
natural resources, reduce the amount of waste generated, and ensure that waste is managed in a manner
that protects both human health and the environment. Subtitle C of RCRA provides EPA primary
authority to promulgate and enforce federal regulations that address management of hazardous wastes
from the initial point of generation to the ultimate point of disposal (i.e., “cradle to grave”). Subtitle D
of RCRA provides EPA authority to promulgate standards for non-hazardous waste disposal; however,
states have the primary authority to implement and enforce these standards. The RCRA statute does
not define which wastes are hazardous and what management practices are most appropriate. These
determinations are made by EPA based on a review of the potential hazards posed by the individual
waste streams.
Regulatory History
When EPA first proposed regulation under Subtitle C of RCRA in 1978, the Agency deferred the
applicability of most of the hazardous waste treatment, storage, and disposal standards for six categories
of “special wastes,” which included drilling muds and oil production brines from oil and gas operations.
This deferral was intended to last until the Agency could perform further investigation into the
composition, characteristics and degree of hazard posed by these large-volume wastes (43 FR 58946).
In response to the proposed rulemaking, both Houses of Congress introduced legislation and held
hearings and debates to determine whether and how special wastes should be regulated. Because it
appeared likely that Congress would act to exempt certain wastes related to utility and energy
development, EPA temporarily excluded the special wastes from the final hazardous waste regulations,
stating that “this exclusion will be revised, if necessary, to conform to the legislation which is ultimately
enacted” (45 FR 33084).
On October 21, 1980, Congress amended RCRA with the 1980 Solid Waste Disposal Act Amendments,
which included provisions that addressed special wastes (Public Law 96-482). Specifically, Section
3001(b)(2)(A) (“the Bentsen Amendment”) temporarily exempted drilling fluid, produced water and
other wastes associated with the exploration, development and production (E&P) of crude oil, natural
gas and geothermal energy from regulation under Subtitle C until further study of the associated risks
had been completed. This provision required EPA to determine whether regulation under Subtitle C
was warranted, submit findings to Congress and publish a final regulatory determination. Furthermore,
it stipulated that any future regulation of E&P wastes under Subtitle C would take effect only if
authorized by an act of Congress.

Management of Exploration, Development and Production Wastes
Section 1: Introduction 1-2

The Agency transmitted a Report to Congress entitled Management of Wastes from the Exploration,
Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy on December 28,
1987 in three volumes that separately covered oil and gas, geothermal, and all associated appendices
(U.S. EPA, 1987a,b,c). EPA concluded in this report that stringent regulation from cradle to grave under
RCRA Subtitle C was not warranted for these wastes because enforcement of existing state and federal
programs would generally be adequate to control the wastes, the large waste volumes generated could
severely strain capacity at existing Subtitle C facilities, and the inflexibility of the Subtitle C program
would create a great permitting burden on regulatory agencies that could result in undue delays for
exploration and production operations. Based on these findings, EPA issued a final determination in
1988 that maintained the exemption from RCRA Subtitle C for E&P wastes associated with primary
field operations (53 FR 25447).
Exemption from RCRA Subtitle C does not mean that these wastes cannot cause harm to human health
or the environment if improperly managed. Rather, EPA concluded that any risks associated with these
wastes could be effectively controlled by improvements to existing state and federal regulatory
programs. Therefore, the Agency has since pursued a multi-pronged strategy that includes further
research, cooperative work with states to review and update programs, federal action outside RCRA
Subtitle C, and voluntary programs to reduce waste generation.
Changes within the Industry
A combination of economic drivers and technological advancements have resulted in changes to the
national energy landscape over the past three decades. The two most significant advancements have
been the widespread adoption of hydraulic fracturing and directional drilling, which allowed expanded
drilling for crude oil and natural gas in black shale and other “unconventional” formations. Hydraulic
fracturing is the injection of fluids into the formation at pressures high enough to fracture nearby rock
and provide conduits for the oil or gas to flow into the well. Directional drilling is the installation of
wells at an angle (deviated or horizontal wells) that allows greater contact between the well and the
formation to maximize the fractured area. Although both technologies have existed in some form for
years, recent innovations allowed combined application to formations that were previously considered
uneconomical to access. Production from unconventional formations represents a growing share of the
national output, though a majority is still produced from “conventional” formations located across the
country. Figure 1-1 illustrates the different types of wells and hydrocarbon-bearing formations that are
currently in production.

Management of Exploration, Development and Production Wastes
Section 1: Introduction 1-3

Figure 1-1: Examples of the Different Types of Oil and Gas Reservoirs and Production Wells.
Conventional hydrocarbon formations are composed of higher-permeability rocks (e.g., sandstone,
limestone, dolomite) that initially produce economically-significant volumes of oil or gas without the
need for hydraulic fracturing. Hydrocarbons typically do not originate in these formations. Instead, the
oil and gas have been driven into these formations from deeper source rocks by a combination of
temperature, pressure, and density gradients. Conventional formations are typically located beneath an
impermeable (“confining”) layer that limits further migration of the hydrocarbons toward the land
surface. Vertical wells are the most common type of well drilled in these formations because the
permeable rock allows hydrocarbons to flow toward a centralized well with minimal assistance. As a
result, vertical wells represent the vast majority of wells that have been drilled to date and all the wells
considered in the 1987 Report to Congress.
Unconventional hydrocarbon formations are composed of lower-permeability rocks (e.g., shale, coal
beds) that must be hydraulically fractured to produce economically-significant volumes of oil or gas.
These formations are often the source rock where the hydrocarbons formed. However, both oil and gas
may also become trapped in other low-permeability (“tight”) formations above the source rock. Drilling
in unconventional formations typically requires directional drilling to maximize the impact of
hydraulic fracturing. As a result, horizontal wells are a growing fraction of new wells drilled in the
United States.

Management of Exploration, Development and Production Wastes
Section 1: Introduction 1-4

Document Purpose and Scope
On May 4, 2016, the Environmental Integrity Project, together with six other parties, filed a lawsuit
with the United States District Court for the District of Columbia that alleged EPA had failed to perform
non-discretionary duties under RCRA, specifically:
 Review, and if necessary revise, Subtitle D criteria for oil and gas wastes (40 CFR Part 257).
 Review, and if necessary revise, state plan guidelines for oil and gas wastes (40 CFR Part 256).
EPA entered into a consent decree on December 28, 2016 that established March 15, 2019 as the
deadline for the Agency to either sign a notice of proposed rulemaking under the aforementioned
statutes or to sign determinations that revisions are not necessary at this time. The deadline was later
extended to April 23, 2019 in response to a temporary lapse in government appropriations that resulted
in unavoidable and cascading delays as a result of the Agency shutdown.
The purpose of this document is to summarize the information currently available to EPA about the
generation, management and ultimate disposition of wastes from E&P operations currently exempt
from regulation under RCRA Subtitle C. These wastes are those associated with primary site operations
integral to the location of hydrocarbon and geothermal reservoirs, extraction of resources, and removal
of impurities necessary to transport the product offsite. This does not include wastes generated as part
of offsite transportation, refinement and manufacturing operations. There are a number of wastes that
fall under this exemption, but not every type is generated at each drilling site. EPA has taken steps to
provide additional clarity on the scope of the E&P exemption through a 1993 Federal Register Notice
(58 FR 15284) and an informational booklet (U.S. EPA, 2002).
EPA conducted a review of publicly available literature drawn from a wide array of government,
industry and academic sources to understand what information has become available since the most
recent update to the Agency’s regulatory framework. This review focused on the structure of the
industry, the volume and composition of wastes generated, actual waste management practices,
applicable state regulations, and documented cases of environmental damage that resulted from any of
these practices. The greatest changes within this industry have been in the production of crude oil and
natural gas. Available data indicate that geothermal energy remains limited to a few states and has not
undergone a similar surge in production. Accordingly, the majority of new information identified in
the literature is focused on production of crude oil and natural gas. Therefore, the discussion in this
document also focuses primarily on these associated wastes.
The information gathered for this document will be used to determine whether a reasonable probability
of adverse effects to human health or the environment exists from the management of E&P wastes.
Based on this review, EPA will identify any further steps necessary to prevent or substantially mitigate
potential sources of harm, which may include updates to regulations or other practical and prudent
non-regulatory actions.

Management of Exploration, Development and Production Wastes
Section 2: Summary of Agency Actions 2-1

2. Summary of Agency Actions
To help fulfill the obligations enumerated in the consent decree, EPA first reviewed existing sources of
information relevant to the current state of E&P waste management and then conducted an extensive
literature review to identify information that had since become available. This section details the
actions previously undertaken by EPA in support of RCRA to improve existing regulatory programs
and enhance understanding of both the industry and the associated wastes. EPA has also taken a
number of additional actions related to E&P wastes under other Agency programs, these actions are
outside the scope of this review.1 Subsequent sections of this document discuss information that was
assembled through the literature review, organized around specific factors that EPA considered
relevant in its review.
1992 Background for NEPA Reviewers
Pursuant to the National Environmental Policy Act (NEPA) and Section 309 of the Clean Air Act, EPA
reviews and comments on major federal actions that may significantly affect environmental quality.
EPA developed a background document on E&P site operations to assist EPA staff with development
of comments on NEPA documents for the exploration and production of oil and gas on federal lands
(U.S. EPA, 1992a). EPA recognized that this document may also be useful to operators that plan work
on federal lands and federal land managers that prepare Environmental Impact Statements.
This document provides general descriptions of site operations, environmental impacts that may be
associated with each operation, possible prevention/mitigation measures, and types of questions that
should be raised as part of the Agency’s review. It is not intended to be exhaustive and does not include
discussion on impacts to floodplains, archaeological resources, and other traditional NEPA concerns
that can be present at any type of development. Rather, it focuses on operations specific to oil and gas
with the greatest potential to impact the environment, which include well site and road construction,
drilling fluid and cuttings management, produced water disposal, product gathering systems (pipelines
and storage tanks), and production operations. The document outlines general concerns about impacts
to groundwater, surface water, air, ecosystems and sensitive receptors, though it acknowledges that
every operation is unique and additional analyses could be necessary to fully understand the risks posed
by a specific project.
1992 Review of Operations in Alaskan North Slope
EPA led a study to evaluate the objectives, implementation and enforcement of the state regulatory
program for E&P wastes on the North Slope of Alaska. This study included information from site visits
to the North Slope by personnel under contract to EPA in 1988; a review of state implementation and
enforcement actions; available information on facility history and waste management practices; and

1) A summary of the different actions taken across the Agency to better understand and address potential environmental impacts
from E&P operations is available online at: https://www.epa.gov/uog.

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Section 2: Summary of Agency Actions 2-2

comments received on a 1989 draft report from the Alaska Department of Environmental Conservation
(AKDEC), the oil and gas industry, environmental groups, and other interested parties. The Agency
completed a report documenting the results of the case study in 1992 (U.S. EPA, 1992b).
EPA found evidence of improved waste management practices on the North Slope and significant
increased attention to environmental issues. However, EPA also observed significant tracts of dead
vegetation during site visits surrounding various service company sites. Service companies perform a
variety of operations on the North Slope, including supplying oil field chemicals, vehicle maintenance,
fuel service and drum disposal. EPA also observed impacted vegetation adjacent to a number of well
pads that appeared to be the result of various spills. EPA documented ongoing activities believed to be
associated with observed damages, such as releases through reserve pit berms and dikes, mishandling
of oily wastes, and poor housekeeping practices with regard to handling of chemicals and equipment.
To address the issues identified during this study, EPA made a series of recommendations. First, to
dedicate additional resources for training, compliance monitoring and enforcement to improve
compliance on the North Slope. Second, to strengthen enforcement of existing regulations, with a focus
on service company operations. Finally, to improve coordination among state agencies to save resources
by eliminating duplication of effort and simplifying compliance and enforcement activities. EPA also
recognized that the state had already taken positive steps to improve the regulatory program for these
wastes. The program had recently been updated, which may not have been fully captured in the
Agency’s report, and additional reviews had been scheduled. In addition, AKDEC had plans for
additional staff positions, though that had not occurred at the time of this report.
1996-1999 Oil Field Waste Pit Program
EPA Region 8 and the U.S. Department of Interior (U.S. DOI) Fish and Wildlife Service (FWS) Region
6 created a team to assess the management of E&P wastes. Co-regulators participating in the effort
included state regulatory agencies, tribal agencies, and the U.S. DOI Bureau of Land Management and
Bureau Indian Affairs. The primary objectives of this effort were to determine where oily waste in open
pits posed a significant threat to migratory birds or other wildlife and to assess the potential threat
posed by these facilities to surface water and groundwater resources. EPA compiled the results of this
effort and provided recommendations to strengthen the effectiveness of state regulatory programs (U.S.
EPA, 2003).
Between 1996 and 1999, sites were assessed in all six states in EPA Region 8 (i.e., Wyoming, Montana,
Colorado, North Dakota, South Dakota, Utah). Initial assessments were conducted by visual inspection
during flyovers. The criterion for identifying potential problem sites was exposed oil, either on the
ground or on the surface of a pit. However, other observed conditions (e.g., discharges to surface water,
abandoned drums) that may pose a risk to human health or the environment were also identified as
warranting further investigation. In less than four years, 15% to 20% of the approximately 28,000 pits
(based on information provided by co-regulators) in EPA Region 8 were observed during aerial surveys.
Many of these sites were found to be well-managed. Most pits (between 80% and 90%) did not present

Management of Exploration, Development and Production Wastes
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an apparent threat to the environment and were not flagged for further attention. 516 sites, some with
multiple pits, were identified as warranting ground inspection and 475 were ultimately visited.
When apparent problems were identified from the aerial assessments, the information was shared with
co-regulators who in turn distributed it to the regulated community. Owners and operators of potential
problem sites were informed that their sites would be inspected no less than thirty days after the initial
contact giving the operators an opportunity to address existing problems. As a result, a large percentage
of flagged sites had addressed the problems prior to ground inspections. Problems that persisted at the
time of the ground inspection were subsequently resolved through either compliance assistance or
enforcement actions (e.g., RCRA Section 7003). In total, 348 informal actions (e.g., notice of violation)
and 80 formal enforcement actions were taken. Of the facilities visited, 61% of production facilities
and 100% of centralized disposal facilities required some sort of follow-up to correct environmental
conditions or non-compliance.
EPA made a series of recommendations to address the waste management issues identified during this
effort. First, to improve communication channels and relationships among co-regulators and Agency
programs by sharing information and improving the collective understanding of the various state and
federal regulatory requirements. Second, to continue improvements to regulatory programs by
incorporating minimum standards compiled by EPA, the Interstate Oil and Gas Compact Commission
(IOGCC), the American Petroleum Institute (API) and other organizations. Finally, to strengthen
compliance monitoring and enforcement, with a particular focus on commercial disposal facilities.
2000 Associated Waste Reports
Data collection in support of the 1987 Report to Congress focused primarily on produced water and
spent drilling fluid which accounted for over 98% of total volume of E&P wastes generated. Many of
the remaining lower-volume wastes were co-managed in the same management units and so were
anticipated to have a minimal impact on the composition of the commingled waste. However, EPA
continued to compile and analyze available information on other E&P wastes from contacts within
other federal agencies, literature reviews, and industry databases to address data gaps that remained for
these lower-volume wastes. In 1992, EPA collected and analyzed samples of wastewater and solid waste
from various E&P operations. These and other available data were discussed in three separate reports,
collectively known as the Associated Waste Reports:
 Tank Bottoms and Oily Debris (U.S. EPA, 2000a)
 Dehydration and Sweetening Wastes (U.S. EPA, 2000b)
 Completion and Workover Fluids (U.S. EPA, 2000c)
These reports summarize information on how the wastes are generated, waste volume and composition,
management practices, and damages that could result from mismanagement. Available information
showed enormous variability in the volume, composition and management of each waste. Yet the small
number of samples relative to the volume and diversity of these waste streams, as well as analytical
issues, such as matrix interference, introduced uncertainty into the data. EPA was unable to determine

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Section 2: Summary of Agency Actions 2-4

whether the data provided a reasonable distribution of waste concentrations or what factors
contributed most to high waste concentrations. These uncertainties prevented the Agency from
drawing broad conclusions about the wastes. However, EPA was able to provide recommendations for
waste minimization and pollution prevention techniques that could be adopted by the industry to
reduce the quantity of waste generated.
2010 Review of Damage Cases
The Natural Resources Defense Council (NRDC) submitted a petition to EPA on September 8, 2010
requesting that E&P wastes be regulated as hazardous under Subtitle C of RCRA. The petition argued
that “the toxicity of exploration, development and production wastes, their release into the
environment, threats to human health, the increasing amount of these types of wastes being generated,
the inadequacy of existing state regulations, enforcement and oversight, and the feasibility and
economic benefits of using disposal techniques that are less harmful to the environment all support
regulation under Subtitle C.” In support of the petition, NRDC provided information on alleged release
incidents of E&P waste. A list of the citations contained in the petition is provided in Appendix A:
(Damage Cases). In response, EPA examined the documents listed in the petition, as well as the
additional sources referenced in those documents, to better understand the nature and frequency of
incidents alleged to have caused harm to human health or the environment.
EPA identified 260 separate incidents from the sources provided that involved management of E&P
wastes in 18 states between 1980 to 2010. Of these, a total of 176 involved management in pits,
12 involved some form of land application (e.g., land farming), 68 involved other miscellaneous releases
(e.g., air emissions, spills), and the remaining four had insufficient information available to reliably
evaluate. The sources also had information on 1,936 reports of citizen complaints, spills and other
releases in three states. EPA examined these additional incidents, but found that many were occurred
some time ago and it was not possible to determine the cause or nature of the incident or the alleged
damage. Therefore, EPA excluded these additional reports from the review.
The vast majority of incidents reviewed were the result of non-compliance with current state
regulations. All but two the 176 incidents related to management in pits and one of the 12 incidents
related to land application could be attributed to violations of state regulations. This indicated that
improved enforcement of existing regulations could have prevented most of the identified incidents.
Based on the review of data provided by NRDC, it remained unclear that imposition of new federal
regulations would substantially reduce issues of non-compliance. Rather it suggested that increased
inspections and tighter enforcement of existing state regulations would reduce the frequency of
violations.
2014 Review of State Regulations
Many states developed and updated legislation and regulations in response to the increased use of
hydraulic fracturing at E&P sites. EPA undertook a review of state regulations to better understand
exactly how state regulations had changed since the 1988 Regulatory Determination and any gaps in

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coverage that may exist (U.S. EPA, 2014a). This review included a direct reading of published state
regulations and statutes for pits and tanks, as well as reports and databases compiled by State Review
of Oil and Natural Gas Environmental Regulations (STRONGER) and the U.S. Department of Energy
(DOE). In total, EPA reviewed regulations from 26 of the 33 states that account for nearly all natural
gas production in the United States. To ensure that the Agency’s understanding and representation of
the state regulations were accurate, EPA followed up with staff from each state agency.
This review did not aim to rank or otherwise evaluate the quality of individual state programs. Instead,
it identified trends and common elements among the states. EPA found that state regulations for pits
and tanks commonly included requirements for liners, secondary containment, minimum setback
distances, minimum freeboard, inspection, maintenance, closure and reclamation. In contrast, states
often did not have requirements for groundwater monitoring, leachate collection, air monitoring or
waste characterization. The absence of these particular requirements is notable because it is a
divergence from typical state programs for other wastes (e.g., municipal solid waste), though it is known
that additional requirements are often included in the facility permits to allow consideration of
differences in local geology, land use, water resources and other factors. However, EPA was not able
to conduct a similarly thorough review of individual permits as part of the analysis.
2014 Compilation of Best Management Practices
The Agency conducted a literature review to develop a list of publicly available sources of best
management practices (BMP, also known as “voluntary management practices”) for E&P wastes in pits,
tanks, and land application/disposal units (U.S. EPA, 2014b). The purpose of this effort was to expand
awareness and encourage the continued improvement of existing BMPs. EPA reviewed a total of 85
publicly available documents and databases developed by industry, state and federal agencies, and non-
governmental organizations that range from international to regional in scope. From this list of sources,
EPA selected 14 examples of BMPs for more in-depth summary. It is important to note that this study
did not aim to evaluate or advocate for any specific practice, rather it was an attempt to provide
information on specific practices in common use throughout the industry.
Based on the review of existing documents, EPA concluded that there is a great deal of existing guidance
on BMPs that is readily available to the public. Many of these sources include recommended technical
criteria for pits and tanks that cover one or more of the following areas: permitting, construction,
operations (e.g., maintenance, inspection, monitoring, testing, remediation), and closure. These criteria
are designed to be flexible and allow practices to be matched and adapted to the needs of the specific
project and local environment. There are also ongoing efforts by various stakeholder groups to
continuously refine and expand upon existing guidance.
1988-2019 Voluntary Initiatives
The Interstate Oil and Gas Compact Commission (IOGCC) was chartered by Congress in 1935 and
represents the governors from 30 oil and gas producing states. In 1988, IOGCC proposed a peer review
for state regulatory programs for E&P wastes. EPA provided grant funding to the IOGCC to develop

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and administer these reviews. The Agency also provided grant funding to citizen groups to encourage
their participation in the state reviews. From 1990 through 1997, the IOGCC administered voluntary
reviews of 17 individual state regulatory programs for the oil and gas industry through a multi-
stakeholder process. When deficiencies were identified, the IOGCC team provided recommendations
for improvements. However, in 1997, this review process was discontinued.
EPA continued to work with the stakeholders to revive the review process and, in 1999, STRONGER
was established as an independent, non-profit educational organization to continue the administration
of state reviews. The multi-stakeholder board of directors includes equal representation from the oil
and gas industry, state and federal regulatory agencies, and environmental public advocacy groups.
EPA provided grant funding and participated on all reviews as an official observer. All reviews are open
to the general public. Altogether, this provides a series of checks and balances to the review process
that ensures the finalized recommendations are appropriate and impartial.
The original guidelines used in the review of state programs were completed in 1990 based on minimum
acceptable standards developed for six topic areas by subcommittees and a survey of existing regulatory
programs in oil and gas producing states.2 These guidelines have been updated multiple times since
then to reflect emerging issues such as abandoned wells, radioactivity, hydraulic fracturing and
recycled fluids. The updates also incorporated EPA guidance developed since 1990. Draft guidelines are
distributed to states, environmental groups, industry associations, and posted on the STRONGER
website for public comments. The comments received are incorporated and a final draft is prepared for
board approval. The most recent update to the guidelines were adopted in 2017 (STRONGER, 2017).
These guidelines extend beyond the scope of RCRA and include recommendations for other topics such
as well construction, data management, and fee calculation.
To date, 22 state programs have been reviewed by IOGCC or STRONGER at least once. These states
collectively account for over 94% of onshore oil and gas production in the United States. A total of 45
separate reviews have been conducted among these states that include 22 initial reviews, 15 follow-up
reviews, and 8 single-topic reviews (i.e., hydraulic fracturing, air quality).3 As of 2009, STRONGER
estimated that over 75% of the recommendations (306 of 405) had been adequately incorporated into
state programs (STRONGER, 2016). These recommendations have led to documented changes to state
programs for pits, tanks, offsite disposal, centralized facilities, spill reporting, corrective action,
remedial standards, and other areas. In addition, some states have taken steps to further characterize
wastes, share information with the public, and increase staffing to support enforcement.
In addition to IOGCC and STRONGER, EPA has also funded initiatives for individual states. These
include grants to Alaska to identify and promote pollution prevention opportunities for the oilfield
service industry (AKDEC, 1994) and to Texas to develop a waste minimization and outreach program
for operators in Texas (TXRRC, 2001). EPA continues to support efforts to reduce the amount of waste

2) The six initial topic areas included: pits, land application, commercial facilities, state and federal relations, personnel and resources,
organization and coordination, and statutory authority.
3) Reports for all STRONGER reviews are made available online at: http://www.strongerinc.org/state-reviews.

Management of Exploration, Development and Production Wastes
Section 2: Summary of Agency Actions 2-7

generated and ensure that waste is managed in a manner that protects both human health and the
environment.

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-1

3. Industry Overview
The oil and gas industry is expansive and encompasses the exploration, extraction, refining, transport
and marketing of oil and gas as a fuel source and feedstock for a range of commercial products. This
document focuses on the upstream sector of the industry that engages in E&P for crude oil and natural
gas from subsurface formations. This section summarizes the available information on the structure of
this industrial sector, the operations performed in the course of normal business operations, and the
types and quantities of waste that may be generated in the process.
Summary of Site Operations
The first step in E&P operations is a pre-siting assessment of local geology to determine the potential
for oil and gas production. Areas that might contain oil or gas reserves are first identified using field
surveys and seismic data before obtaining the mineral interests on the property from the landowner
and approval to drill from the relevant state agencies. Exploratory wells may initially be installed onsite
to gather more detailed geological data on rock and fluid properties, initial reservoir pressure, and
reservoir productivity. If exploratory wells identify a formation that can produce salable quantities of
crude oil or natural gas, then the development wells may be installed to extract the hydrocarbons.
Well exploration, development and production involves a wide array of operations to install the well,
extract the hydrocarbons, remove of impurities from the crude oil and natural gas prior to distribution,
and maintain the long-term integrity of the well. The following text provides a general summary of
common operations that may be performed during the installation and productive life of a well, as well
as the wastes that may be generated. This discussion is not intended to provide an exhaustive list of
operations or waste types; this document groups wastes into broader waste streams based on similar
composition and management practices.
3.1.1. Well Installation
A drilling pad is first prepared to support a drilling rig and any ancillary equipment, such as trucks
associated with the operation and trailers to house personnel and equipment. The size of a pad typically
ranges between one-half and one acre, depending on the nature of the operation and the number of
wells that will be drilled. The lease or property boundaries and well location are staked out and the site
is excavated to clear the area of trees and other vegetation. Then an access road (“lease road”) is built
and any pits and tanks needed to manage waste are installed.
Modern oil and gas wells are typically drilled with rotary drill rigs. These rigs rotate the drill pipe with
an attached drill bit (“drill string”) to create the borehole (“wellbore”). As drilling progresses, additional
drill pipe segments are added in successive sections (“joints”). The threads on each joint are coated with
a compound that protects the threads and prevents seizing when the joints are connected together. At
predetermined intervals, drilling is halted and the drill string is removed from the wellbore to install a
steel casing. The purpose of this casing is to prevent collapse of the surrounding rock into the wellbore,
isolate high-pressure formations, prevent intrusion of formation fluids into the wellbore during

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-2

construction, and avoid mixing of hydrocarbons and other contaminants with overlying aquifers during
production.
The first interval of casing (“conductor casing”) extends a relatively short depth, typically between fifty
and several hundred feet, to prevent collapse of the initial wellbore and to provide support for deeper
casing strings. After each interval is installed, cement may be pumped down the casing to seal the
annular space. When drilling resumes, the drill bit is advanced to a point just below where the next
casing string or surface casing will extend. The second interval of casing (“surface casing”) is smaller in
diameter and typically extends anywhere from 50 to 100 feet below the lowermost aquifer of potential
use, as specified by state requirements. Subsequent intervals of casing (“intermediate casing”) are
installed as needed to reach the target formation and isolate unstable formations that may collapse or
cause loss of fluid circulation. If this interval is located in a stable (“competent”) formation, the operator
might choose not to install intermediate casing and produce through an open hole. The final interval
of casing (“production casing”) typically runs the full depth of the well and isolates the production zone
from other formations. Figure 3-1 provides an example of standard well casing configurations.

Figure 3-1: Diagram of Standard Well Casing Configurations.
Wells may be advanced directly beneath the well pad (“vertical well”) or at an angle that can extend
some distance beyond the footprint of the well pad (“deviated well”). The initial portion of a deviated
well is typically vertical and drilled the same as any other vertical well. At the point the well begins to
deviate (“kickoff point”), the curved section of the well is drilled using a hydraulic motor mounted
directly above the bit and powered by the drilling fluid. This allows the drill bit to be rotated by the
hydraulic motor without also rotating the drill pipe. Various sensors in the drill string provide
information about the location and speed of the bit and the temperature and pressure of the formation,
which allows precise control over the movements of the drill string. Deviated wells may be installed at
a range of different angles, though wells in unconventional formations are often installed fully parallel
with the hydrocarbon formation (“horizontal well”) to allow greater contact between the well and the
formation for hydraulic fracturing.

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-3

During well installation, an engineered fluid is circulated down the drill pipe and out of nozzles in the
drill bit (“drilling fluid” or “drilling mud”). This fluid is used to cool and lubricate the drill bit, control
pressure within the borehole, seal drilled formations to prevent fluid loss, and to transport drill cuttings
to the surface. The type of drilling fluid used depends on the characteristics of the formations that will
be drilled:
 Gas-based fluids (GBFs) can be entirely gas (carbon dioxide, nitrogen) or may be gas entrained in
water with foaming agents (e.g., surfactants). GBFs are used to drill wells under low-pressure and
low-temperature conditions in relatively shallow wells and formations like limestone and coalbeds.
 Water-based fluids (WBFs) typically consist of 80% water and 20% clay and other additives. The
water can be either fresh or salt water. WBFs are used to drill deeper wells under moderate-to-high
pressures and low-to-moderate temperatures.
 Oil-based fluids (OBFs) typically consist of around 55% petroleum distillate, 30% water, and 15%
clay and other additives. OBFs are used to drill wells under extreme temperatures and pressures
where water could evaporate or freeze (e.g., Arctic drilling) or where reactive formations could be
encountered (e.g., hydratable shale, salt domes).
 Synthetic-based fluids (SBFs) are formulated similar to OBFs. SBFs are oil-like fluids formulated
from vegetable esters derived by reacting an acid with an alcohol, olefins or alkenes (e.g., ethene),
synthetic paraffins (paraffin-like material produced from natural gas), and alkyl benzenes (single
ring aromatic hydrocarbons). SBFs are formulated to biodegrade more quickly in the environment
and have lower bioaccumulation potential. These synthetic fluids tend to be more expensive and so
are primarily used when drilling in environmentally sensitive areas, such as offshore and coastal
areas, that require performance equivalent to an OBF.
Drilling fluid may simply be foam, fresh water or salt water at the start of drilling. However, as drilling
progresses and formation pressures and temperatures increase, new fluids may be introduced that
contain additives to increase the weight and enhance the performance of the fluid. Weighting agents
are commonly added to increase the specific gravity (weight) of the fluid. Barium sulfate is often used
as the weighting agent in WBFs, OBFs and SBFs but hematite (iron oxide) may also be used, particularly
in OBFs. Another common additive is clay (typically bentonite) to further increase the specific gravity
of the fluid and to help protect and seal wellbore formations.
Drilling fluids return to the ground surface through the annular space between the drill pipe and the
wellbore. The used fluids are mixed with the fragments of soil, rock and other pulverized material that
are dislodged by the drill bit (“drill cuttings”). Cuttings are mechanically separated from the drilling
fluids to the extent practicable with equipment such as filter belts or centrifuges and sent to a reserve
pit or tank. Recovered drilling fluids are treated and reused until the fluids become too contaminated
to recycle, the geological conditions in the wellbore require new fluid formulation, or drilling has been
completed. At that point, the spent drilling fluid is also sent to the reserve pit or tank. Drill cuttings
and spent drilling fluid are the wastes generated in greatest volumes during well installation. A number
of other wastes may be generated in smaller volumes that include spent spotting fluid, water used to

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-4

wash the drill rig, and spills of various materials around the drill rig (e.g., cement) may be generated in
smaller volumes over the course of drilling. These wastes are typically managed together with the drill
cuttings and drilling fluid in onsite reserve pits or tanks prior to disposal.
3.1.2. Well Completion and Production
Once the well has been installed, any drilling fluid remaining in the well is replaced with a dense fluid
free of any solids that could react with the formation water or otherwise plug the production zone.
This fluid is often a heavy brine made with dissolved inorganics salts (e.g., chloride, bromide) that is
used to control the pressure down-hole and to prevent formation fluids from entering the well while
the well is completed. Once the completion fluid is in place, a perforating gun loaded with shaped
charges is lowered into the production zone and remotely fired. The charges pierce the casing and
cement, creating holes that will allow oil and gas to flow into the wellbore once the completion fluid
is removed.
Well stimulation techniques may be used after well completion to widen and connect conduits in the
formation and allow the oil and gas to flow more freely into the well. Acid may be injected at lower
pressures and allowed to remain within the well for some time to dissolve any limestone, dolomite or
calcite minerals present within the reservoir rock. Other fluids may be injected at higher pressure to
create new fractures within the rock, also known as hydraulic fracturing. Common base fluids for
fracturing are water or an energized mixture of water and entrained gas (e.g., nitrogen, carbon dioxide).
Less common base fluids may be a mixture of water and petroleum distillate or entirely hydrocarbons
and alcohols. In specific cases, acids may be used as the primary fracturing fluid to dissolve carbonate
reservoirs. After the initial fracturing, gelling agents are added to increase the viscosity of the fluid and
to facilitate transport of a proppant into the fractures so that the pressure in the formation does not
reseal the fractures. Common proppants include various sizes of sand, ceramic beads and sintered
bauxite. Next, a gel breaker is injected into the well to reduce the viscosity of the fracturing fluid and
allow it to return to the surface without the proppant. These fluids may also contain a number of other
additives intended to protect the integrity of the well and the formation during injection, such as
friction reducers, scale and corrosion inhibitors, biocides and others. Further discussion of these other
additives can be found in the Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical
Disclosure Registry 1.0 (U.S. EPA, 2015a).
The fluids produced from a well are typically some mixture of crude oil, natural gas and associated
water. This mixture is immediately directed to one or more oil and gas separators that use baffles or
other means to partition the different phases based on density. Natural gas rises to the top of the tank.
Depending on the volume of gas generated and the available infrastructure, the natural gas may be
flared off or collected for sale. Natural gas may require additional treatment to remove impurities prior
to sale. Common treatments include passing the gas through specialized filters to remove either water
vapor (“dehydration”) or acidic gases, such as hydrogen sulfide and carbon dioxide (“sweetening”).
These treatments may produce other salable products, such as elemental sulfur, compressed carbon
dioxide, and natural gas liquids (e.g., propane, butane). The remaining natural gas, which is primarily

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-5

methane, is sent to a transmission line for transport for sale.4 The separated crude oil is skimmed off
the top of the water and sent to a heater treater that accelerates the breakdown of any emulsified water
by applying heat. The remaining crude oil is sent to tanks for storage until it can be transported offsite
for sale or further refinement. Figure 3-2 provides an example of typical operations to separate out oil
and gas for transport.

Figure 3-2: Typical Production Operation for Oil, Gas, and Water Separation.
The waste generated in the greatest volume during production by far is the wastewater that flows from
the well. At first, the wastewater might be composed primarily of hydraulic fracturing fluids that have
returned to the surface (“flowback”), but over time the injected fluids will mix with the water in the
hydrocarbon-bearing formation (“formation water”). This mixing makes it difficult to determine what
fraction of the wastewater originates from the formation at any given time. Therefore, the waste liquids
generated from a well are collectively referred to as “produced water.” At the ground surface, produced
water is separated from any salable hydrocarbons and sent to pits or tanks for storage prior to disposal
or recycling back into fracturing fluids.
Another waste routinely generated during production consists of solids that settle out and accumulate
in flowlines, pits, tanks and other equipment along the production line. These solids are commonly
referred to as sediment, sludge or vessel bottoms. Depending on where in the production line the
sediment accumulates, it may contain a variable mixture of proppant, formation solids, chemical
precipitate, paraffins, condensed liquids, heavy hydrocarbons and other substances that settle out of
solution. These solids must be cleaned out of the pits and tanks periodically and are expected to be
managed as a separate waste stream. Cleaning may be done manually or with the aid of mechanical

4) Because natural gas often requires processing to remove water vapor and other impurities prior to entering the sales line, gas
plants are considered to be part of primary operations regardless of the location with respect to the wellhead.

Management of Exploration, Development and Production Wastes
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devices (“pigs”) used to scrape the insides of narrow pipes and flowlines. If the solids contain high levels
of oily residue, the solids may be sent to a crude oil reclamation facility to salvage the oil. Occasionally,
if the solids have a high fluid content, they may be disposed along with the produced water. Otherwise,
the solids are likely to be sent as a separate waste stream for disposal.
A number of additional waste streams may be generated periodically during oil and gas production at
far smaller volumes than produced water. Examples include filter socks used to remove solids from
produced water, spent sorbents used to remove impurities from natural gas (e.g., glycols, amines, solid
desiccants), and backwash used to the clean filters for reuse. Backwash and other wastewater may be
managed in the same pits and tanks as produced water, but spent filters and sorbents are expected to
be handled as a separate waste stream for disposal.
3.1.3. Well Maintenance
A variety of maintenance operations (“workover operations”) may be required during the operational
life of a well to maintain or enhance production. It may be necessary to first stop the flow of production
fluids from the formation by pumping a high-density fluid similar to the completion fluids down the
well to control formation pressure. If the well is damaged, it may be necessary to repair or replace
downhole equipment. If the hydrocarbon formation becomes plugged with sand, paraffin or other fine
grained materials, it may be possible to use a combination of hot liquids, acids and other physical or
chemical treatments to remove the accumulations. If production cannot be restored, other options may
include re-stimulating the well through hydraulic fracturing, plugging the wellbore with cement and
re-completing the well in an upstream location, or re-drilling the well into a deeper production zone.
Because many of these operations are similar to those conducted for well installation and completion,
many of the wastes generated are also similar.
One distinct workover waste is pipe scale that forms when oversaturated minerals precipitate out of
produced water and adhere to the inside of production tubing and gathering lines. Scale buildup can
clog pipes and cause significant drops in production. Some types of scale can be readily removed
through a combination of acid solution or mechanical scrapers. The dissolved or dislodged scale will
then become incorporated into settled solids or other waste streams. However, some types of scale are
highly recalcitrant and may require equipment to be removed from service in order to dislodge the
scale. In some cases, the equipment may be disposed with the scale still intact. Given the difficulty of
removal, this type of scale is expected to be managed and disposed as a separate waste stream.
Oil and Gas Production Rates
Both the U.S. DOE Energy Information Administration (EIA) and the Independent Petroleum
Association of America (IPAA) compile statistics on crude oil and natural gas production in the United
States. Available data show that onshore production occurs in 34 states, though a minority of states
account for the majority of production. Table 3-1 summarizes the states with the greatest number of
active (i.e., producing) wells. These data were drawn primarily from The Distribution of U.S. Oil and
Natural Gas Wells by Production Rate (U.S. DOE, 2018a). This dataset does not currently include any
data for Idaho, Illinois or Indiana and so total well counts were drawn from relevant state agency

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-7

websites. The number of gas wells in these three states were drawn from the EIA data series, Number
of Producing Gas Wells (U.S. DOE, 2018b) and the number of oil wells was calculated by subtraction.
Table 3-1. Estimated Number of Active Wells in 2016 by State
Rank State Total Number
of Wells
Number of
Oil Wells
Number of
Gas Wells
Percent of
All Wells
1 Texas 309,970 174,654 135,316 29.5%
2 Oklahoma 83,977 36,002 47,975 8.0%
3 Pennsylvania 80,426 11,489 68,937 7.7%
4 Kansas 74,050 51,326 22,724 7.1%
5 New Mexico 58,338 17,837 40,501 5.6%
6 West Virginia 56,971 3,704 53,267 5.4%
7 Colorado 54,987 8,885 46,102 5.2%
8 California 52,848 48,865 3,983 5.0%
9 Ohio 45,154 13,124 32,030 4.3%
10 Louisiana 36,777 19,003 17,774 3.5%
11 Wyoming 33,783 10,090 23,693 3.2%
12 Illinois 32,100 32,064 36 3.1%
13 Kentucky 19,705 5,145 14,560 1.9%
14 North Dakota 14,396 13,942 454 1.4%
15 Michigan 13,595 3,689 9,906 1.3%
16 Utah 12,622 4,192 8,430 1.2%
17 Arkansas 11,671 1,875 9,796 1.1%
18 New York 10,873 3,120 7,753 1.0%
19 Montana 10,173 4,645 5,528 1.0%
20 Virginia 8,161 9 8,152 0.8%
Top 20 States 1,020,577 463,690 556,917 97.2%
All U.S. Wells 1,049,560 481,781 567,779 100%

Total Illinois Wells: https://www.dnr.illinois.gov/OilandGas/Pages/AboutOilAndGasInIllinois.aspx

The IPAA estimated there were a total of 1,072,973 active wells (578,167 oil and 494,806 natural gas)
in 2016 (IPAA, 2017). These counts differ somewhat from EIA estimates, though the overall order of
magnitude is the same between the two sources. The IPAA does not provide a similar breakout by state,
which prevents more in-depth comparisons. Counts by well type are complicated by the fact that
individual wells can produce a mixture of crude oil and natural gas. For record-keeping purposes, wells
are often designated as either oil or gas based on which is produced in greater quantities.5 Thus, well
counts do not provide a reliable proxy for the total production of oil or gas in individual states. Table
3-2 summarizes data on oil and gas production in the highest producing states from the EIA data.

5) One barrel of oil is equivalent to approximately 6,000 ft3 of natural gas.

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-8

Table 3-2. Estimated Crude Oil and Natural Gas Production in 2016 by State.
Rank
Crude Oil Production Natural Gas Production
State Volume
(MMBL)
Percent of
Total Volume State Volume
(Bcf)
Percent of
Total Volume
1 Texas 1,176 36.4% Texas 8,126 24.8%
2 North Dakota 378 11.7% Pennsylvania 5,313 17.0%
3 California 186 5.8% Alaska 2,868 10.1%
4 Alaska 179 5.5% Oklahoma 2,468 7.8%
5 Oklahoma 154 4.8% Wyoming 1,848 6.7%
6 New Mexico 146 4.5% Louisiana 1,708 5.6%
7 Colorado 116 3.6% Colorado 1,702 5.5%
8 Wyoming 73 2.2% Ohio 1,440 5.2%
9 Louisiana 56 1.7% West Virginia 1,375 5.0%
10 Kansas 38 1.2% New Mexico 1,285 4.1%
11 Utah 31 0.9% Arkansas 823 2.2%
12 Montana 23 0.7% North Dakota 609 2.1%
13 Ohio 22 0.7% Utah 365 1.0%
14 Mississippi 20 0.6% Kansas 243 0.7%
15 Illinois 9 0.3% California 196 0.7%
16 Alabama 8 0.3% Virginia 120 0.5%
17 West Virginia 7 0.2% Michigan 101 0.4%
18 Pennsylvania 6 0.2% Alabama 100 0.3%
19 Michigan 6 0.2% Kentucky 92 0.3%
20 Arkansas 5 0.2% Montana 52 0.2%
Top 20 States 2,640 82% Top 20 States 30,834 95%
Total U.S. 3,232 100% Total U.S. 32,592 100%
MMBL = Million Barrels
Bcf = Billion Cubic Feet
Crude Oil Production: https://www.eia.gov/dnav/pet/PET_CRD_CRPDN_ADC_MBBL_M.htm
Natural Gas Production: https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FGW_mmcf_a.htm

The IPAA estimated national production to be 3,231 MMBL of crude oil and 32,800 Bcf of natural gas
(IPAA, 2017), which align well with EIA estimates. It is clear from EIA data that production varies
considerably among states and that a greater number of wells does not always translate to higher
production. One reason is the age of the wells. Although wells can be re-stimulated by various means
to recover output, production will inevitably decrease over time as the local reserves are depleted.
Wells that no longer produce more than 10 BL of oil or 60,000 ft3 of natural gas per day are classified
as marginal wells (or “stripper wells”). The Interstate Oil and Gas Compact Commission (IOGCC)
estimated that in 2016 a total of 396,023 oil wells and 381,334 gas wells had marginal production. These
wells account for around two-thirds of active wells in the country and nearly all of the wells in some
states. Altogether, marginal wells are estimated to produce between 284 and 404 MMBL of crude oil
and 1,880 and 2,760 Bcf of natural gas, around 10% of nation-wide production (U.S. DOE, 2016a,b;
IOGCC, 2017; IPAA, 2017). While the number of marginal oil wells and associated production have
remained steady over the last two decades, the number of marginal gas wells and associated production

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-9

have nearly doubled (IPAA, 2017). This change reflects broader trends in the oil and gas industry over
this time period. Table 3-3 provides a comparison of industry statistics from 2016 with those reported
in the 1987 Report to Congress.
Table 3-3. Change in Industry Statistics, 1985 to 2016
Source
Source: U.S. EPA (1987a) Source: IPAA (2017) % Change
EPA IPAA IPAA IPAA
Total Active Wells 842,000 889,970 1,072,973 +20.6%
Wells Completed per Year 70,000 70,796 14,379 -79.7%
Petroleum Production (MMBL) 3,650 3,274 3,231 -1.3%
Natural Gas Production (Bcf) 16,100 19,600 32,600 +66.3%
MMBL = Million Barrels
Bcf = Billion Cubic Feet

This comparison shows that production of oil has remained stable over the past three decades, while
production of natural gas increased substantially. The increase in natural gas production is attributed
primarily to the adoption of directional drilling and hydraulic fracturing that allowed access to oil and
gas trapped in black shale and other unconventional formations. In 2016, a total of 14,379 wells were
completed. Over the same time period, the number of active horizontal wells increased by around 6,200
(IPAA, 2017; U.S. DOE, 2018a). Figure 3-3 shows the location of the major tight oil and shale gas plays
across the United States. It is notable
that many states with these plays are
also those with the greatest annual
production volumes (e.g., Texas,
Oklahoma, Pennsylvania).
A simple comparison of production
statistics at two points in time does
not provide a complete picture of
how the industry changed in the
intervening time. The production
boom in the early 2000s resulted in a
dramatic increase in the number of
oil and gas wells drilled, though the
annual number of wells never
reached the same levels reported in
1985. Over the same period, oil and
gas production increased substantially. The increased production has been maintained so far, even as
the number of new wells decreased in recent years. Figure 3-4 provides a year-by-year comparison of
the number of wells completed each year and the annual production volume over the past two decades
(IPAA, 2017; U.S. DOE, 2018c,d).
Figure 3-3: Major Shale Gas and Tight Oil Plays
Source: (U.S. DOE, 2018d)

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-10

Figure 3-4: Comparison of Well Completion and Production Volume, 1997 to 2017.
The recent decline in the number of drilled wells reflects advances in the available technology and
drilling techniques. Between 2000 and 2016, the fraction of wells in operation that are horizontal
increased from 1% to 12% (U.S. DOE, 2018a). Horizontal wells provide greater contact between the
well and the reservoir rock and so are capable of producing greater volumes of product. In 2017, only
1% of vertical wells were able to produce more than 100 BL/day of crude oil, but 30% of horizontal
wells exceeded this production volume (U.S. DOE, 2018e). The growing number of horizontal wells
have allowed sustained production growth even as the well count has fallen. Current forecasts predict
that production from tight oil and shale gas formations will continue to grow into 2019, driven in part
by recent discoveries in the Permian basin (U.S. DOE, 2018f; U.S. DOI, 2018).
Waste Generation Rates
The exploration and production of crude oil and natural gas generates substantial quantities of waste
compared to many other industrial sectors. However, information on waste volumes is not routinely
collected nationwide. Although some states collect and maintain data on the wastes generated within
their respective boundaries, the methods and metrics used to collect these data are not uniform
(U.S. GAO, 2012). In addition, some states exempt certain wastes from regulation and so data may not
be available. This makes it difficult to compare and aggregate data on a wider scale.
Some recent efforts have been made to provide estimates for individual wastes. The U.S. DOE Argonne
National Laboratory (ANL) estimated that 21,000 MMBL of produced water were generated in 2007
(U.S. DOE, 2009), while the Ground Water Protection Council (GWPC) estimated a total of 21,180
MMBL were generated in 2012 (GWPC, 2015). However, these estimates do not fully capture the
increased production in unconventional formations or the more recent decline in the number of wells
completed each year. Therefore, these estimates may no longer be fully representative.
The most recent national-scale estimates for many E&P wastes are from the American Petroleum
Institute (API, 2000). API used data from a 1995 survey to calculate relationships between production
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Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-11

metrics (e.g., volume of oil produced) and the volume of waste generated. These relationships were
then used to scale waste volumes based on various production metrics in 2000. For the purposes of this
discussion, EPA used the same relationships to update waste volumes based on more recent production
metrics. Table 3-4 summarizes the estimated waste generation in 2016.
Table 3-4. Estimated E&P Waste Generation in 2016
Waste Type Density
(Tons/BL)
Volume
(MMBL)
Mass
(MM tons)
Percent of
Total
Drilling Fluids/Mud 0.21 93.4 19.6 0.4%
Drill Cuttings 0.23 33.5 7.5 0.2%
Stimulation/Workover Fluids 0.18 7.2 1.3 < 0.1%
Settled Solids 0.24 2.7 0.64 < 0.1%
Pipe Scale Insufficient Data Available
Produced Water 0.18 24,942 4,452 97.7%
Natural Gas Treatment Residuals 0.18 0.31 0.06 < 0.1%
Wastewater Treatment Residuals 0.31 249 77 1.7%
Hydrocarbon Bearing Soil and Debris 0.22 1.8 0.4 < 0.1%
Total 25,330 4,559 100%
MMBL – Million Barrels

Use of the same scaling factors assumes that the relationships between production and waste generation
have remained constant over time. However, the volume of waste generated by a given well is related
to the type of hydrocarbon produced, the geographic location of the well, and the method of production
(U.S. GAO, 2012). Therefore, shifts in overall type, location and age of wells can all affect this
relationship. API estimated that, between 1985 and 1995, the average volume of produced water
generated for every barrel of oil increased by 1.4 barrels as a result of growing population of aging wells
in conventional formations (API, 2000). Since that time, the existing fleet of wells has continued to age
and newer wells have been drilled in unconventional formations. These new wells tend to be drilled a
greater distance through the producing formation and generate greater quantities of produced water
early in the life of the well. As a result, current estimates may underestimate waste volumes to some
degree. Nevertheless, these estimates still provide a reasonable comparison of relative waste volumes.
Produced water is the E&P waste generated in the largest volume by far and this is unlikely to change.
However, this does not mean that the other wastes are not as environmentally significant.
Economic Structure
Under RCRA, EPA is generally prohibited by statute from considering cost as a basis for whether
regulation is necessary. However, the Agency is also required by executive order to quantify both the
expected costs to the industry and benefits to human health and the environment from significant
regulatory actions. This information allows the Agency to transparently assess and communicate the
potential impacts of different actions to the public. Therefore, EPA assembled available data on the
economic structure of the oil and gas industry.
The North American Industry Classification System (NAICS) is the standard used by federal agencies
to classify business establishments for the purpose of collecting, analyzing and publishing statistical

Management of Exploration, Development and Production Wastes
Section 3: Industry Overview 3-12

data related to the economy. The NAICS numbering system employs a 2 to 6-digit code that designates
individual industrial sectors with increasing specificity based on the number of digits. The entire
upstream oil and gas subsector is captured by the 3-digit code NAICS 211: Oil and Gas Extraction. The
industry can be further subdivided into two 6-digit NAICS national industries: NAICS 211120: Crude
Petroleum Extraction and NAICS 211130: Natural Gas Extraction. The information in this section is
profiled at the 3-digit NAICS industry segment level.
A number of organizations collect data on the economic conditions of the oil and gas industry and the
contributions to the U.S. economy. For example, both the Bureau of Economic Analysis and the EIA
collect data on the consumption and production of crude oil and natural gas and petroleum products,
and the Federal Reserve Bank reports capacity utilization for the industry which measures how much
capacity is being used of the total available capacity for production. A variety of peer-reviewed
publications have analyzed the market structure, pricing, and concentration of the industry and there
are a variety of sources used to assess the financial conditions of firms in the industry (i.e., SEC filings
are available to assess the financial conditions of public companies). The following text provides a brief
summary of available data on revenue and employment in the oil and gas industry.
3.4.1. Revenue
Revenue data provide insight into the economic conditions of the oil and gas industry over time.
Economic Census data are widely used to assess economic impacts as a percentage of revenue; however,
these data are only collected every five years. Table 3-5 summarizes the available data on revenue in
the Oil and Gas Extraction sector from the Economic Census for years 2007 and 2012. Data for the 2017
Economic Census are not slated for release until September 2019.
Table 3-5. NAICS 211: Oil and Gas Extraction – Revenues
Year Number of
Establishments
Value of sales, shipments,
receipts, revenue, or other
business (Million $)
Average sales, shipments, receipts,
revenue, or other business per
establishment (Million $)
2012 6,735 $310,960 $46.1
2007 6,260 $255,105 $40.7
Percent Change 17.96% 11.74%
Source: https://www.census.gov/programs-surveys/economic-census/data/tables.html

Between 2007 and 2012, the overall Oil and Gas Extraction sector experienced increases in revenue.
EIA predicts natural gas and natural gas liquids have the highest projected production growth (U.S.
DOE, 2019). The EIA predicts strong growth in U.S. natural gas production, but points towards
heightened uncertainty regarding future oil supply and demand as a result of international market
conditions, though EIA’s natural gas price projections depend more on domestic factors that drive
supply, including domestic resource and technology assumptions, than on international conditions
(U.S. DOE, 2019).
3.4.2. Employment
The Economic Census collects data on the number of individuals that are employed at both the firm
and establishment level. The U.S. Census Bureau (Census) considers an establishment to be a single

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physical location where one predominant activity occurs, while a firm can have multiple
establishments defined by a unique Employer Identification number issued by the Internal Revenue
Service. The Economic Census provides extensive statistics on U.S. businesses, but the data are only
collected every five years, most recently in 2012. The Census also collects the Statistics of U.S.
Businesses series annually, which provides more limited data. Table 3-6 reports the number of firms,
establishments and employees by employment size in the NAICS 211: Oil and Gas Extraction sector by
using data from the Statistics of U.S. Businesses, which has historical data available back to year 1988.
Table 3-6. Oil and Gas Extraction - Employment in 2016
Employment
Size
Number of
Firms
Number of
Establishments Employment
0-4 3,913 3,919 6,562
5-9 818 830 5,306
10-19 427 446 5,562
20-99 396 481 14,203
100-499 98 246 14,858
500+ 108 1,408 75,649
Total 5,760 7,330 122,140
Source: https://www.census.gov/data/tables/2016/econ/susb/2016-susb-annual.html

Combining the data on employment with the number of reported firms provides an estimate of the
average employment per firm. In 2016, the Oil and Gas Extraction sector employed an average of 21
employees per firm. The Small Business Administration defines small firms as having 1,250 or fewer
employees for both NAICS 211120: Crude Petroleum Extraction and NAICS 211130: Natural Gas
Extraction. By this standard, the percentage of small firms and establishments in the industry is high.
Over 99 percent of firms are considered small, while over 80 percent of establishments are considered
small.
3.4.3. Resolution of Available Data
EPA is not aware of any publicly-available sources that provide economic data for this industrial sector
at a finer resolution than the establishment or firm level. There is little information available about the
number and type of wells, pits, tanks and other relevant operational units associated with each
establishment or firm. Therefore, it is difficult to know how the costs of regulatory requirements for
specific types of operational units, such as wells, pits, or tanks, would be distributed across the industry.
Any evaluation of potential economic impacts would require extrapolation and estimation of cost and
revenue based on some assumptions about the number and type of operating units present. This
represents a major source of uncertainty in any analysis.

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4. Waste Management
Wastes that are generated over the course of E&P operations must be managed prior to disposal or
reuse. There are a variety of options for onsite or offsite management available. The purpose of this
section is to describe the most common methods to store and dispose of waste that fall under the
jurisdiction of RCRA. Although a large fraction of wastes are ultimately disposed through injection
wells, either for disposal or enhanced recovery (GWPC, 2015), these specific practices are not addressed
in this document.
EPA attempted to assemble specific information from state permits for the various waste management
units (e.g., pits, landfills, land application facilities); however, a comprehensive review of these permits
was not feasible at this time. The number of permits and associated documentation is enormous and
often requires foreknowledge of individual wells or waste management units to access each one
(e.g., well number, county). Therefore, this section instead aims to use available information to provide
a general overview of different waste management practices for E&P waste and some of the major
environmental design considerations for each.
Pits
Pits (alternately referred to as “impoundments,” “ponds,” “lagoons” or “sumps”) are generally excavated
areas of land where waste is placed for temporary storage or ultimate disposal. These pits are typically
constructed below grade, though there may be berms or dikes around the perimeter that extend above
the ground surface. The size of the pit is dictated primarily by the volume of waste that will be
generated. Therefore, pits that service multiple wells will tend to be larger.
There is limited information available on the current number of pits in operation. Between 1996 and
2002, EPA estimated a total of 28,000 pits at E&P sites across Colorado, Montana, North Dakota, South
Dakota, Utah and Wyoming (U.S. EPA, 2003). In 2019, Colorado reported a total of 3,426 active pits
(CODNR, 2019), which is a substantial decrease from the 10,950 pits previously estimated in this state
by EPA despite the increase in shale gas production over the past decade. It is unknown whether a
similar decrease has occurred in other states. The literature suggests that multi-well pits are becoming
more common and may include water recycling systems to provide water for drilling and completion
of subsequent nearby projects (Carpenter, 2014). Regardless of location, pits have a number of design
considerations based on the types of materials managed and applicable state regulations.
Pits may be constructed with compacted local soils or lined with a range of different materials, such as
concrete, compacted clay or high-density polyethylene. Liners may be installed to prevent infiltration
of stored fluids into the underlying soil. This prevents loss of materials (e.g., fresh water) or release of
contaminants to the surrounding environment (e.g., produced water). Figure 4-1 provides an example
of two separate pits with a geomembrane liner. The larger pit contains drill cuttings, while the smaller
pit contains drilling fluid that will be circulated into the well.

Management of Exploration, Development and Production Wastes
Section 4: Waste Management 4-2

Figure 4-1: Pits with Visible Liners.
Source: Left: Bill Cunningham, U.S. DOI Geological Survey; Right: U.S. EPA
Most pits are open to the air, which may allow birds and other wildlife to come in direct contact with
the waste. These pits may not attract birds during the drilling process due to human activity and noise.
However, once the drilling rig and other equipment are removed from the well pad, animals may be
attracted to the water and insects entrapped in the pit fluids (U.S. DOI, 2009). A number of states
recommend or require netting or another type of barrier around pits to prevent access by wildlife and
intruders. Fencing and netting may be constructed from a range of materials, such as chain link, barbed
wire, and fabric. Figure 4-2 provides examples two pits with both fencing and netting.

Figure 4-2: Pits with Fencing and Netting.
Source: Left, U.S. DOI Fish and Wildlife Service; Right, U.S. EPA
State regulations specify over 20 different types of pits based on various factors, such as the duration
the pit will be in use (e.g., temporary, permanent), the stage of operations (e.g., drilling, production) or
the materials that will be managed (e.g., fresh water, produced water). However, the terminology used
by different states can overlap and conflict. Therefore, EPA focused on broad categories of pits for the
purposes of this general discussion.

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4.1.1. Reserve Pits
Reserve pits are used for the storage of the wastes (e.g., drill cuttings, spent drilling fluid) generated
during well installation. The primary wastes that are managed in these pits include drill cuttings and
spent drilling fluids. However, used completion fluids and other miscellaneous, smaller-volume wastes
may also be placed in these pits. Reserve pits are temporary and only active until the well has been
installed and the wastes have either been removed or prepared for disposal in place. Installation time
varies considerably but is generally on the order of a few weeks to a few months. Most states require
closure of reserve pits within 6 to 12 months of completion of drilling so the total length of time a
reserve pit may be present on a site is expected to be between 6 and 15 months. As a result of the
relatively short lifespan of these pits, it is anticipated that the majority of units currently in operation
have been constructed in compliance with current state regulations. However, reserve pits that service
multiple wells on a single pad may operate for longer periods of time.
It is unknown how many reserve pits are currently in operation. Under the assumption that there is
one reserve pit associated with each well drilled, there could have been as many as 14,379 new reserve
pits created in 2016 (IPAA, 2017). The actual number is likely to be lower, as some sites will use tanks
or centralized pits. Pits are sized primarily based on the total length that will be drilled, which can vary
considerably based on the formation and the type of well. Horizontal wells can generate anywhere
between 30 and 70% more cuttings than vertical wells (Johnson and Graney, 2015). A study conducted
by the U.S. DOI Fish and Wildlife Service reported that pits in two areas of Wyoming range in size
from 10,200 to 24,000 ft2 (U.S. DOI, 2009). A recent study in Texas estimated the average area of reserve
pits designed for long residence times to allow solids to settle out was 75,000 ft2 with a volume of 25
MBL (Redmon et al., 2012). SkyTruth reviewed aerial photography around permitted drilling locations
to identify the number and size of pits across Pennsylvania. Table 4-1 provides the estimated number
of pits and associated areas identified by this effort. The same effort also tracked the presence of pits
over time and found that nearly 80% of the pits identified were no longer present three years later.
This indicates that many of the pits identified onsite are likely to be shorter-lived reserve pits.
Table 4-1. Summary of Pit Sizes in Pennsylvania
Year Number of Pits Average Area (ft2) Median Area (ft2)
2005 11 1,998 1,132
2008 237 3,415 1,834
2010 581 11,211 6,568
2013 529 24,780 20,374
Source: https://www.skytruth.org/2014/10/pa-drilling-impoundments-2005-2013/

When well installation is completed, the free liquids in the reserve pit are generally removed to the
extent practicable, either through pumping or evaporation. The remaining solids are a mixture of drill
cuttings and residual solids left by the drilling fluids that may include additives, such as bentonite clay
and barite. Any residual liquids that are intermingled with these solids may be stabilized with lime or
fly ash prior to disposal. Pits may be closed in different ways depending on state requirements. In some
states, the waste solids may be disposed in place by folding the liner over the dewatered drill cuttings

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Section 4: Waste Management 4-4

and backfilling the pit with soil. In other states, the cuttings and any liner must be removed and
disposed of at an offsite facility approved by the state to accept E&P wastes.
4.1.2. Production Pits
Production pits are used for the storage of wastes generated during well production. The primary waste
managed in these pits is produced water. These pits will also gradually accumulate sludge at the bottom
of the pit from settling of suspended solids and precipitation from produced water. Other smaller-
volume wastes may also be placed in these pits. These pits can be present throughout the lifespan of a
well, which may extend anywhere from 15 to 50 years. EPA identified one state that reported the
number of production pits. The California State Water Board conducted an inventory of pits that
contain produced water, as well as the numbers that are both lined by the state. Table 4-2 provides a
summary of reported active production pits as of January 2019.
Table 4-2. Number of Active Production Pits in California
Region Total Lined Unlined
Central Coast 41 32 9
Los Angeles 76 76 0
Central Valley 561 31 530
Santa Ana 2 0 2
Total 680 139 541
Source: https://www.waterboards.ca.gov/water_issues/programs/groundwater/sb4/oil_field
_produced/produced_water_ponds/

EPA identified little information about the typical size of production pits. However, pits associated
with horizontal wells are expected to be much larger than other pits to accommodate the large volumes
of produced water generated. EPA previously estimated that between 0.3 and 1 million gallons (7.1 to
23.8 thousand barrels) of water can be produced in the first 10 days after hydraulic fracturing, primarily
from the flowback of injected water (U.S. EPA, 2016a). Due to the large volume of waste produced over
a short period of time, such large pits may not always be economical to construct onsite. Centralized
pits in the Permian Basin of Texas have been reported to be as large as 320,000 ft2 (McEwan, 2012).
When production is complete, the liquids in the production pit are removed to the extent practicable.
This may be accomplished through pumping, evaporation or discharge to ground or surface water.
Liquids that are removed from the pits may be disposed or recycled for use at nearby wells. It has been
estimated that hydraulic fracturing produced about 660,000 MBL of produced water for disposal in
2017 and of that, about 14% was treated and reused (Presley, 2018). Additional treatment may be
applied to solid residuals (e.g., sludge) including thickening, stabilization, and dewatering processes
prior to disposal. These solid residuals may be sent to a landfill, land spread, or incinerated (Morillon
et al., 2002).

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4.1.3. Other Pits
There are a number of other specific pits that may
be present at E&P sites. Some of these pits may
be used to hold specific wastes, such as well
blowdown or gas processing condensate. Other
pits may be used for specific events. For example,
emergency pits are used to contain excessive or
unanticipated amounts of fluids generated during
an emergency situation in the drilling or
operation of a well, such as a well blowout or a
pipeline rupture. Flare pits are intended to collect
any liquids that remain after hydrogen sulfide
and other gases are burnt off. Figure 4-4 shows
an example of a flare pit. These pits are not intended for the prolonged storage of waste and are typically
emptied as soon as possible after use. There is little information available on the number of these pits.
However, because of the specific uses for these pits, the size tends to be much smaller than reserve or
production pits.
Tanks
Tanks are prefabricated structures used both to separate waste from product and to store wastes prior
to transport offsite. Tanks may be installed aboveground or below the surface. The size of individual
tanks typically ranges between 100 to 1,000 BL, depending on the rate of production. The number of
tanks needed at a site will vary based on the quality and quantity of crude oil, natural gas and produced
water generated. If a well produces high-quality oil and little gas or water, a site may only require a
single tank to store oil. However, a site with heavy oil and substantial gas or water production may
need anywhere from two to ten tanks to separate and manage the various products and wastes. Multiple
tanks at E&P sites are commonly grouped together in batteries that include the tanks, flow lines and
the other equipment necessary to manage produced fluids. Colorado reported a total of 1,561 active
tank batteries (CODNR, 2019). Under the assumption that the prevalence of tank batteries is similar
among states and there is an average of three tanks per battery (i.e., separator, heater-treater, storage),
EPA scaled the number reported for Colorado for each state based on the number of active wells and
estimated there to be around 90,000 tanks across the country. However, this number may be higher in
high-producing regions. Regardless of the number of tanks, there are a number of design considerations
that depend on applicable state regulations and both the quantity and quality of the oil produced.
Tanks and the associated piping may be constructed from a variety of materials, such as steel, fiberglass
or polyvinyl chloride. Each material has specific strengths and weaknesses based on the temperature,
fluid corrosiveness, service pressure, duration of production, and operating costs at a given site. Steel
can sustain high-pressure flow and is easily welded, but can be prone to corrosion when exposed to
highly saline fluids (e.g., produced water). Although steel may be coated to protect against corrosion,
these treatments may not be effective at extreme temperatures (Heintz, 2005). Fiberglass tanks are light
Figure 4-3: Flare Pit.
Source: U.S. DOI Fish and Wildlife Service

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Section 4: Waste Management 4-6

and resistant to corrosion, but are less conductive and so may be more susceptible to damage from
lighting strikes if not properly grounded (Wood, 2014). Polyvinyl chloride is a relatively inexpensive
option, but is not well-suited for high-pressure flow.
Tanks may leak during operation as a result of damage (e.g., puncture), degradation (e.g., corrosion) or
human error (e.g., overfilling). Therefore, secondary containment is often required to prevent releases
from migrating from the initial point of release before the spill can be identified and addressed. A
example design recommendation is for secondary containment to be large enough to hold 1.5 times as
much fluid as is stored in the largest tank; however, alternate volumes may be specified by state
regulations. Containment may be constructed from range of materials. Figure 4-5 shows examples of
tank design with secondary containment.

Figure 4-4: Tanks with Secondary Containment.
Sources: Left, U.S. EPA; Right, UWCE (2005)
4.2.1. Closed-Loop Drilling
Closed-loop drilling fluid systems are an alternative to reserve pits in which the flow path is not open
to the atmosphere. In a closed-loop system, a series of tanks are used together with specialized
equipment (e.g., screen shakers, hydrocyclones, centrifuges) to separate drilling fluid from drill cuttings
and other solids. This process minimizes the amount of fluid retained on the waste solids and maximizes
the amount of fluid recycled back into the drilling process. Minimizing the volume of waste solids
through fluid removal results in less waste ultimately disposed (Redmon et al., 2012). Prior to disposal
this dried waste may be stored in piles or dumpsters prior to transport offsite. Use of closed-loop drilling
is often considered a best management practice (NMEMNRD 2000; TXRRC, 2001).
4.2.2. Production Tanks
When a well begins to produce salable quantities of oil or gas, additional tanks are required to separate
the product from the waste. The most common types of production tanks are separator tanks (e.g., wash
tanks, settling tanks, gun barrel tanks) that use density differences to separate crude oil, natural gas and
produced water; heater-treater tanks that use heat from the sun or another source to rapidly break
down emulsions of oil and water; and storage tanks that hold the separated materials until ready for

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Section 4: Waste Management 4-7

transport for sale or disposal. The composition of a tank battery may change over the life of the well.
Tanks may be added or removed to support changes in the volume of oil and produced water generated.
As the nature of production changes, different specialized equipment will need to be brought in to
meet different needs. For example, a well may initially have sufficient natural pressure to maintain
flow. However, as the natural pressure falls, it may be necessary to add equipment, such as a hydraulic
lift to maintain production. Figure 4-6 shows an example of the types of production tanks that may be
present at E&P sites.

Figure 4-6: Diagram of Production Tanks.
Source: Courtesy of ESD Simulation Training, Inc.
Tanks are neither intended nor suited for the disposal of waste. Therefore, at the end of the useful life,
all tanks should be cleaned out and transported offsite. This involves draining fluids from the tank and
removing any solids (i.e., sludge) that have accumulated on the tank bottom. The tanks that are
removed may be disposed, reused or recycled depending on the state of the tank.
4.2.3. Modular Large Volume Tanks
Modular large volume tanks (MLVTs) are freestanding aboveground tanks assembled in the field with
sectional frame that supports a synthetic liner that provides primary containment for fluids. These
types of tanks are more easily dismantled after use for transport to another location. However, because
of the greater number of seams present in the tank structure, there may be greater risk of catastrophic
failure if the tanks are not properly assembled and maintained. These tanks have been used to hold
both fresh water for use in hydraulic fracturing operations and wastewater from E&P operations,
though some states may place restrictions on the materials that may be stored in these tanks. Figure 4-
6 shows some examples of modular tanks.

Management of Exploration, Development and Production Wastes
Section 4: Waste Management 4-8

Figure 4-5: Modular Large Volume Tanks.
Source: Tipton (2013)
Land Application
Land application is the general practice of disposing of waste on surficial soils. Some states use different
terminology (e.g., land treatment, landfarming) to distinguish between application of different waste
types or method of application (e.g., surface spread, tilled). The primary purpose of this practice is to
promote decomposition of organic compounds. After application, the soil may be periodically tilled to
amend the soil with nutrients or aerate the waste to promote decomposition. Figure 4-8 shows some
examples of how E&P wastes may be land applied to the soil.
Land application may occur onsite around the
well pad or offsite. Offsite disposal may occur at
state permitted facilities or on private land with
the agreement of the landowner. It has been
reported that farmers have been paid to allow
application of E&P waste to lower-productivity
rangeland or pasture. It is unknown what effects
the application of E&P waste may have on the
quality and productivity of the soil; this is an area
of ongoing research (OCES, 2017).
There are a number of design considerations for land application units based on the waste disposed and
where it is applied. Onsite applications typically occur only once and are generally limited to cuttings
drilled with water-based fluids. Offsite application may occur multiple times with a wider range of
wastes. States may place restrictions on the types of waste applied based on measured level of organics
(e.g., total petroleum hydrocarbons [TPH]), salts (e.g., chloride), and radioactivity (e.g., radium) or
based on the types of waste considered likely to have high levels of these constituents (e.g., oil-based
drilling fluid, horizontal cuttings). Restrictions may also be placed on where the waste is applied to
limit the potential for offsite migration (e.g., permeable soil, steep slope, flood zones).
Figure 4-6: Land Application of E&P Wastes.
Source: OCES (2017)

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Section 4: Waste Management 4-9

EPA did not identify any formal records of application onsite or offsite to private land. Offsite land
application is addressed in the regulations of at least eleven other states, though the location and
number are not publicly available (U.S. DOE, 2006). The size of land application facilities is often
unknown. Facilities identified in Texas range between 12 acres divided into 4 separate cells and 517
acres divided into 17 cells. One permit in Kansas shows an area of 160 acres divided into 10 separate
cells (KCC, 2012).
Other Offsite Disposal
There are a number of options for disposal of E&P waste at offsite facilities. Costs vary depending on
the location of the disposal facility, the method used for disposing of the waste, the type of waste, and
the extent of competition in the local or regional area. Although the costs of disposal are an important
consideration, transportation costs, laboratory fees, and other associated costs will also influence the
decision. Generally, operators will not be inclined to transport waste more than 50 to 75 miles unless
no other alternatives are available (U.S. DOE, 2006).
The availability of offsite facilities dedicated to E&P wastes varies by state. A 2006 report conducted by
the Argonne National Laboratory found that eight states with higher oil and gas production had a
dedicated network of offsite disposal facilities overseen by the state regulatory agency (i.e., Arkansas,
Colorado, Louisiana, New Mexico, Oklahoma, Texas, Utah, Wyoming). Seven states with less oil and
gas production did not have the same degree of infrastructure (i.e., Alabama, Michigan, Mississippi,
Nebraska, North Dakota, Pennsylvania, West Virginia). The remaining states had no industry-specific
infrastructure (i.e., Alaska, Arizona, California, Florida, Illinois, Indiana, Kansas, Kentucky, Missouri,
Montana, New York, Ohio, Tennessee, South Dakota, Virginia) (U.S. DOE, 2006). It is likely that states
without dedicated facilities for E&P wastes rely on the existing infrastructure for disposal of other solid
wastes (e.g., municipal solid waste landfills) to manage E&P wastes.
4.4.1. Landfills
Offsite landfills may be used for the disposal of certain E&P waste solids. These permitted landfills may
accept waste from a range of sources (e.g., municipal solid waste landfills) or may be dedicated solely
to E&P wastes. The wastes must meet the acceptance criteria for the landfill and so the composition of
the waste may determine the type of landfill selected. States have reported rejecting drill cuttings for
use as alternate daily cover as a result of high TPH and oily residue (ASTSWMO, 2015). The number
of offsite landfills that accept E&P wastes is not known. However, based on a review of state regulations
and websites, EPA is aware of both commercial and municipal solid waste landfills accepting certain
E&P wastes. Recent reports indicate that there is a trend in states with high oil and gas production
toward dedicated landfills (Karidis, 2017). In Texas, multiple new disposal facilities have recently been
constructed that include composite liners, leak detection systems, and groundwater monitoring
(Sandoval, 2018).

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4.4.2. Other Treatment and Disposal Facilities
Other treatment and disposal facilities may be used for the management of E&P waste solids and
liquids. This broad category of facilities is differentiated from landfills because the wastes sent to these
facilities are not permanently disposed on the ground surface. These facilities may be owned and
operated by one or more oil and gas operators (“centralized facilities”) or by entities other than the oil
and gas operator (“commercial facilities”). Some examples of treatment include crude oil reclamation
and wastewater treatment. Treatment can result in the reclamation of a useful product that might be
sold (e.g., crude oil), but can also generate new wastes that may be more concentrated than the original
E&P waste and must be disposed appropriately (e.g., water treatment residuals). Examples of disposal
include underground injection, percolation and evaporation. These facilities may use pits and tanks,
similar to those found near the wellsite, to store waste prior to treatment or disposal. Figure 4-9
provides examples of an evaporation pit with sprayers used for disposal of produced water (left) and a
centralized pit used for storage of produced water prior to water treatment (right).

Figure 4-7: Treatment and Disposal Facilities.
Sources: Left, Tipton (2013); Right, U.S. DOI (2013)
Information on the total number of different treatment and disposal facilities that accept E&P wastes
is limited. Between 1996 and 2002, EPA identified 36 centralized disposal facilities across Colorado,
Montana, North Dakota, Utah and Wyoming (U.S. EPA, 2003). EPA more recently estimated that up
to 74 centralized water treatment facilities may accept waste liquids from hydraulic fracturing (U.S.
EPA, 2016a). The Texas RRC provides a current list of 107 permitted “commercial recycling and surface
disposal facilities,” more than half of which are located in the Permian Basin. Many of these facilities
are dedicated to reclamation or recycling of waste, though 28 are also permitted for disposal of
treatment residuals. Several of the permits reviewed from Texas note the that residual wastes may be
disposed through onsite burial, deep well injection, or burial in RCRA Subtitle C facilities. These
permits also provide specifications for the size of pits, along with detailed requirements for waste
acceptance, constructing, waste testing, operating, groundwater monitoring, and closure. Table 4-3
provides examples of the types and sizes of pits present at select facilities in the Permian Basin.

Management of Exploration, Development and Production Wastes
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Table 4-3. Examples of Disposal Pit Sizes in the Permian Basin
Facility Name Facility Size Pit Type Number Pit Area (ft2) Capacity (MBL)
Howard County
Treatment, Recovery
and Disposal Facility
144 Acres
Receiving 3 99,500 94.3
Collecting 1 130,000 76.1
Disposal 5 798,000 5,100 to 6,700
Wishbone Facility Not
Provided
Receiving 2 4,000 4.3
Disposal 10 Various Sizes 280 to 11,000
Midland SWD/Sludge
and Disposal Facility 39.2 Acres
Collecting 3 6,000 to 88,200 1.6 to 23.7
Disposal 4 1,500 to 448,200 900 to 2,900
Source: https://www.rrc.state.tx.us/oil-gas/applications-and-permits/environmental-permit-types-information/commercial-
surface-waste-facilities/commercial-recyclingdisposal-permits-list/

Beneficial Use
Beneficial use is a broad term that describes the practice of utilizing non-hazardous materials in a
productive fashion as an alternative to disposal. State programs generally have an administrative
mechanism in place that allows a generator to submit a request for a specific beneficial use. The relevant
state agency reviews the request to determine whether the proposed use is appropriate. Beneficial use
determinations are often made on a case-by-case basis after consideration of factors, such as the benefit
provided, the long-term performance of the use, and any potential risks to human health or the
environment (U.S. EPA, 2013). In some states, the structure for these determinations is clearly defined
and tools, such as application forms and detailed guidance, have been made available to assist the
applicants. In other states, regulatory language is written broadly and the specific data collection and
demonstration requirements are not specified upfront.
In 2013, the Association of State and Territorial Solid Waste Management Officials (ASTSWMO)
conducted a survey of state management practices. A total of 11 states of the 28 that responded to the
survey indicated they had approved various beneficial uses, such as drill cuttings (road base, concrete,
grading), drilling fluid (concrete), sludge (road application), and produced water (dust suppressant, de-
icing) (ASTSWMO, 2015). Other uses that have been reported for produced water in some western
states include livestock watering, irrigation, and streamflow supplementation (U.S. DOI, 2011).
Approval for these and other uses is often predicated on the use meeting certain criteria. States have
reported rejecting proposed uses because of unsuitable composition, either physical (e.g., grain size) or
chemical (e.g., oil and grease, chloride, radium, sulfate) (ASTSWMO, 2015). However, there is little
publicly available information about the frequency at which different states have approved beneficial
uses, the volumes that have been diverted to these uses, and where the uses occur.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-1

5. Waste Characterization
EPA conducted a literature review on the composition and environmental behavior of wastes generated
during well exploration and production operations. This information is needed to characterize the
potential magnitude of exposures that may result if wastes are released into the environment. As part
of this review, EPA assembled data for multiple types of wells (e.g., oil, coal bed methane, geothermal)
into an E&P constituent database. The majority of identified data are for oil and gas wells in non-coal
formations. These are the most numerous wells drilled across the country, both historically and
currently. These wells were also the primary focus of Onshore Oil and Gas Human Health and
Environmental Risk Assessment (U.S. EPA, 1987). Therefore, the review of data in this document
focused on wastes from these wells. Further discussion of the approach to assemble and review the data
are provided in Appendix B (Constituent Database).
Each of the following subsections summarize the available data for an individual waste type. Where
feasible, EPA calculated summary statistics for the concentration and activity of inorganic elements,
organic compounds and radioisotopes (“constituent levels”) in each waste type. When factors that
might affect waste composition were identified, EPA separated out the data to facilitate comparison
and discussion. In particular, EPA focused on potential differences between the wastes from horizontal
and vertical wells as a proxy for conventional and unconventional formations to understand whether
and to what extent hydraulic fracturing might affect waste composition. EPA did not compare wastes
from individual formations because it would further subdivide the available data and make meaningful
comparisons more difficult. The summary statistics and comparisons presented in this document are
intended to provide the Agency’s current understanding of constituent levels based on available data,
which in some cases are limited in quantity and geographic coverage. Even if the statistics do not
capture the full variability of each waste, the calculated values still provide useful information on the
possible magnitude of constituent levels in each waste, the relative constituent levels among different
wastes, and where data gaps still exist.
Spent Drilling Fluid
Drilling fluids (also referred to as “drilling muds”) are the materials used during well installation to cool
and lubricate the drill bit, control pressure within the borehole, seal drilled formations to prevent the
loss of drilling fluid into the formations and the influx of water from the formation into the borehole
(i.e., annulus), and to transport drill cuttings to the surface. These fluids are pumped downhole through
a hollow drill string and exit through nozzles in the drill bit back to the surface through the space
between the drill and the walls of the borehole. Once back at the surface, drilling fluid is mechanically
separated from the drill cuttings with equipment such as filter belts or centrifuges and treated to the
extent necessary for reuse. The fluids are considered spent once the composition is no longer suitable
for reuse, when changing geological conditions in the well require a new fluid formulation, or when
the wells are complete (U.S. EPA, 1987d). Spent drilling fluids are assumed to be managed primarily as
an aqueous waste, though there are known instances where the fluids are evaporated or otherwise

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-2

dewatered prior to disposal as a solid. However, few data were identified for the residual solids and so
EPA did not separately discuss leachate from this waste.
5.1.1. Bulk Concentration
Drilling fluid is initially composed of a base fluid (e.g., water), solids (e.g., bentonite, cellulose) and
other chemical additives. The majority of drilling fluids use water as a base (API, 2000). As a result, the
majority of available data are for water-based fluids. However, oil- and synthetic-based fluids are still
used to address specific drilling scenarios, such as clay formations that could expand in the presence of
water. Additionally, compressed gases (e.g., air, nitrogen) have been used to drill in certain carbonate
and coal formations. Thus, EPA incorporated the limited data available for other drilling fluids.
However, due to the near absence of data on these other fluid types, it is not possible to draw any
separate conclusions about the resulting wastes.
Although the composition of the fluids is precisely engineered prior to use, the fluids will mix with
cuttings and formation water during drilling. This can introduce contaminants into the fluid that are
then transported back to the surface. The scope of treatment is often limited to restoring the physical
properties of the fluid necessary for reuse (U.S. DOI, 2011). As a result, recycling has the potential to
result in further accumulation of contaminants in the fluid.
Inorganic Elements
EPA identified a total of four studies that measured inorganic elements in drilling fluid. Three of these
studies drew samples from vertical wells in at least eight states (U.S. DOE, 1979; API, 1987; U.S. EPA,
1987d). EPA did not identify information that could be used to further weight the data to obtain a more
representative national distribution, such as the volume of waste generated in each state. Therefore,
data from each state were weighted equally. One other study drew samples from horizontal wells in
Pennsylvania (Shih et al., 2015). Table 5-1 presents the 50th and 90th percentile summary statistics of
available data for inorganic elements in drilling fluid.
Table 5-1. Inorganic Elements in Drilling Fluid (mg/L)
Constituent Vertical Wells Horizontal Wells
n 50th 90th n 50th 90th
Arsenic 5 / 8 0.01 0.02 10 / 12 0.03 0.18
Barium 8 / 8 1.3 4.9 32 / 32 23.8 1,810
Boron 8 / 8 0.85 6.1 32 / 32 2.5 15.1
Chloride 8 / 8 2,000 33,000 35 / 35 17,000 89,000
Chromium 4 / 8 0.05 0.16 13 / 21 0.25 1.3
Copper 4 / 8 0.01 0.03 12 / 20 0.17 0.53
Lead 2 / 8 0.07 1.0 12 / 13 0.05 0.30
Manganese 8 / 8 0.19 5.6 32 / 32 2.9 13
Molybdenum 6 / 8 0.13 0.20 11 / 13 0.11 0.41
Nickel 2 / 8 0.05 0.15 13 / 19 0.20 0.39
Sodium 8 / 8 2,100 16,000 33 / 33 11,400 33,900
Strontium 8 / 8 4.1 223 35 / 35 63 1,558
Zinc 5 / 8 0.07 0.20 18 / 25 0.09 1.7
n = Number of Samples Detected / Total

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-3

Concentrations from horizontal wells are generally higher than those from vertical wells. However, it
is difficult to determine whether all of the observed differences are significant. The vertical dataset
consists primarily of single samples from various states, which are unlikely to capture the full variability
of any formation. The horizontal dataset shows there can be considerable variability within individual
formations. At the same time, the horizontal dataset consists entirely of unfiltered samples. Additional
constituent mass from solids suspended in solution could overestimate differences when compared with
filtered vertical samples. Despite these uncertainties, the data still provide useful information that can
be used to better understand the sources constituent mass and the potential differences between wastes
from vertical and horizontal wells.
Barium exhibits the greatest proportional increase in concentration between the two datasets. If total
suspended solids (TSS) are the source of high measured concentrations, then there must be a solid that
is enriched in barium. Cuttings from the formation are likely to have similarly enriched concentrations
of other common elements, such as iron and manganese. Another potential source of barium in drilling
fluid is barite (BaSO4). Barite is a common and high-density additive to drilling fluid. Industry-grade
barite is typically greater than 90% BaSO4 (U.S EPA, 1985). The low solubility of the barite mineral
will keep most barium from dissolving into solution and so could contribute to disproportionately high
barium concentrations. If barite is the source of high barium concentrations, there should be a
relationship between TSS and barium. Figure 4-1 presents a graph of the relationship between TSS and
barium in the samples from Shih et al. (2015).
There is no relationship between barium and TSS; the
highest barium concentrations correspond to some of
the lowest TSS concentrations. Therefore, barite is not
the primary source of barium in these samples. It is
more likely that the suspended barite settled out of
solution (“barite sag”). The other potential sources of
dissolved barium are the water used as a base fluid and
the formation water that mixes with drilling fluid in
the borehole. The median barium concentration in
formation water reported by Shih et al. (2015) is
1,010 mg/L. This is orders-of-magnitude higher than
concentrations in either surface water and surficial
groundwater, which rarely exceed 0.3 mg/L (ATSDR,
2007). Thus, formation water is the most likely source
of barium in the drilling fluid from horizontal wells.
Another notable difference between vertical and horizontal wells is lead, which is the only constituent
with higher concentrations measured in vertical wells. This may only be the result of small sample size,
as the higher summary statistics are driven by a single sample. A similarly high sample is also present
in the horizontal dataset, though it does not exert the same influence on the distribution. In both cases,
the highest concentration is an order of magnitude greater than the remaining samples. There are a
R² = 0.00
0.1
1
10
100
1000
10000
100000
Ba
r
i
u
m

(
m
g
/
L
)
Total Suspended Solids (mg/L)
Figure 5-1: Relationship Between Barium
and TSS in Spent Drilling Fluid

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-4

number of possible sources for lead. Naturally-occurring sulfide deposits can contain high
concentrations of lead, zinc and other metals. Some of these deposits are known to be located alongside
hydrocarbon-bearing formations (Kharaka et al., 1987; Leach et al., 2010). Another possible source is
the materials used to construct the wells. One compound, commonly known as “pipe dope,” is used to
seal pipe joints and can contain more than 30% lead by weight (Kahn, 2011). This lead may leach into
the drilling fluid as it circulates through the well (NRC, 1983). There is not enough information
available to determine the source of the higher lead in these samples. However, this highlights the need
to understand not only drilled formations, but also the drilling practices to fully understand potential
waste composition.
Organic Compounds
EPA identified two studies that measured the organic compounds in drilling fluid. One study drew
samples from vertical wells in seven states (API, 1987). EPA did not identify information that could be
used to further weight the data to obtain a more representative national distribution, such as the
volume of waste generated in each state. Therefore, the data from each state were weighted equally.
One study drew samples from horizontal wells in one state (Shih et al., 2015). Table 5-2 presents the
50th and 90th percentile summary statistics of the available data for organic compounds in spent
drilling fluid.
Table 5-2. Organic Compounds in Drilling Fluid (mg/L)
Constituent Vertical Well Horizontal Well
n 50th 90th n 50th 90th
Benzene 1 / 6 0.003 0.007 6 / 15 0.003 0.05
Toluene 3 / 7 0.005 0.01 7 / 15 0.008 0.20
Ethylbenzene 1 / 6 0.003 0.005 1 / 1 0.009
Xylene 0 / 0 -- 1 / 1 0.11
n = Number of Samples Detected / Total

A majority of both vertical and horizontal data are non-detect. As a result, median concentrations often
reflect a detection limit. Horizontal data have a higher detection frequency despite similar detection
limits and have higher detected concentrations. This indicates that prolonged contact with formations
with high-organic content may result in greater accumulation of organic compounds. However, further
conclusions about the magnitude of any differences are limited by the amount of data available.
Radioisotopes
EPA identified two studies that measured radioactivity in spent drilling fluid (Shih et al., 2015; PADEP,
2016). These studies collected samples from horizontal wells in one state. Samples were only analyzed
for radium isotopes because the lower solubility of other radionuclides were expected to result in
dissolved activities far lower than radium (PADEP, 2016). Table 5-3 presents the 50th and 90th
percentile summary statistics of the available data for radium in drilling fluid.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-5

Table 5-3. Radioisotopes in Spent Drilling Fluid (pCi/L)
Isotope
Horizontal Well
n 50th 90th
Radium 226 28 / 28 90.6 1,863
Radium 228 28 / 28 18.3 400
n = Number of Samples Detected / Total

The data show that both median and high-end activities of 226Ra and 228Ra are clearly elevated in spent
drilling fluid from horizontal wells. Radium does not serve a function in the fluid and so is not
intentionally added, though it might be a contaminant present in additives. EPA identified two studies
that separately sampled the solid fraction of some drilling fluids (WVDEP, 2013; PADEP, 2016). The
studies collected samples from horizontal wells in two states. These solids are expected to be a mixture
of various additives along with some residual drill cuttings. In addition to radium, the samples were
measured for uranium and thorium because of the greater potential for these radioisotopes to be present
in the solid phase at comparable activities (PADEP, 2016). Table 5-4 presents the 50th and 90th
percentile summary statistics of available data for radioisotopes in the solids from drilling fluid.
Table 5-4. Radioisotopes in Residual Solids from Drilling Fluids (pCi/g)
Isotope
Horizontal
n 50th 90th
Uranium 235 2 / 9 0.06 0.10
Uranium 238 8 / 14 0.84 1.1
Radium 226 14 / 14 1.3 3.5
Radium 228 14 / 14 0.33 1.8
n = Number of Samples Detected / Total

Radium activities in the solids phase are substantially lower than the associated fluids from the same
study, despite prolonged contact between the two media. Reported 226Ra activity appears to be higher
than the parent 238U, which might indicate an outside source of radium in these samples. However, as
noted by PADEP (2016), 226Ra activities measured directly by gamma spectroscopy can be biased high
when radium and uranium are both present at similar levels because current instruments cannot fully
distinguish the energy signatures of 226Ra and 235U. The authors made no attempts to account for this
interference in the reported data. If 226Ra and 238U are in approximate equilibrium (i.e., no major
outside source or sink of radium), then there should be some relationship between 235U activity and
the magnitude of excess 226Ra in each sample. Figure 5-2 presents the relationship between 235U and
excess 226Ra based on the raw gamma measurements.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-6

The strong relationship indicates that a majority of
excess 226Ra activity can be attributed to interference
from 235U during measurement. Thus, 226Ra in these
samples is likely to be near equilibrium with 238U.
After adjustment for interference, 226Ra activities all
fall below the upper bound of 4.2 pCi/g measured in
surface soil (U.S. DOE, 1981a). It is unclear why
exposure to high-activity fluids does not result in
enriched solids. It is possible that high dissolved
solids in the fluids compete for binding sites on the
surface of the solids and force the radium to remain
in solution (Sturicho et al., 2001; IAEA, 2014). These
results indicate that additives and other suspended
solids are not the primary source of radium in spent
drilling fluid. This is further corroborated by a comparison of total and dissolved activities in formation
water samples reported by PADEP (2016), which found dissolved activities to be only 2% lower on
average.
The potential sources of dissolved radium are the water used as a base fluid and the formation water
that mixes with the drilling fluid within the borehole. The median activity in formation water reported
by Shih et al. (2015) is 1,680 pCi/L 226+228Ra. This is several orders of magnitude greater than activities
typically found in either surface water or surficial aquifers, which generally have a combined radium
activity less than 5 pCi/L (ATSDR, 1990; Szabo et al., 2012). Therefore, formation water is the most
likely source of activities reported in drilling fluid.
EPA identified one additional sample of solids from drilling fluid taken from Colorado; however, this
sample was solidified prior to disposal in the landfill (CHDT, 2015). Although drilling fluids are
typically disposed of as aqueous waste, high-solids fluids may be solidified prior to disposal on land.
This sample is greatly enriched in radium, with a 226Ra activity of 91 pCi/g and corresponding 238U
activity of only 0.2 pCi/g. The report provides no discussion on the materials used in solidification of
the waste. Materials commonly used for other wastes include cement and fly ash. Like most materials
drawn from the earth, these pozzolanic materials contain some radium. However, neither of these
materials have been reported to have such disproportionately high radium activity (U.S. EPA, 1979;
UNSCEAR, 2000). The more likely source of radium is drilling fluid, which has been shown to have
disproportionately high radium activities that could easily support the activity measured in the
solidified sample. If residual drilling fluid is used to hydrate a pozzolanic material, then the dissolved
radium could be incorporated into the solidified mass. Alternately, if the drilling fluid were allowed to
evaporate before solidification, this could also concentrate radium in the remaining solids. This suggests
that waste management practices have the potential to result in higher activities than predicted based
on measurement of solids alone. This represents a major source of uncertainty in the available data.
R² = 0.80
0
1
2
3
4
5
0 0.1 0.2 0.3 0.4 0.5
22
6
Ra

-
23
8
U
(
p
C
i
/
g
)
235U (pCi/g)
Figure 5-2: Relationship Between 235U and
Excess 226Ra in Residual Solids from Drilling
Fluid

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-7

5.1.2. Summary – Spent Drilling Fluids
This review highlights the complexities of deep well drilling. Potential sources of constituent mass
include additives to the drilling fluid, leaching from equipment, and mixing with the formation. In the
borehole, drilling fluid is exposed to reducing conditions under elevated temperature and pressure. The
fluid is then brought back to the surface where it is exposed to oxygen before being cycled through the
borehole again. This process can be repeated multiple times before the fluid is spent and ultimately
disposed. The impact of shifting environmental conditions on drilling fluid during use have not been
well-explored in the literature. Therefore, any conclusions must be drawn from measurements of spent
drilling fluids. The available data indicate that a major source of constituent mass in water-based
drilling fluids is mixing of the drilling fluid with formation water in the borehole. Constituent levels
(i.e., concentrations and activities) measured in formation water are sufficient to support levels
measured in drilling fluid, though other sources previously mentioned also have the potential to
contribute additional constituent mass. Available studies did not characterize produced water from the
same wells, so it is not possible to determine the actual extent that mixing occurred in any sample.
The data available to characterize this waste are limited. Some studies only provide individual data
points and so do not capture variability in any of the formations sampled, while others provide multiple
samples for only a single formation. This makes it difficult to draw conclusions about the typical
composition of this waste or the exact magnitude of any differences between vertical and horizontal
wells. However, if the primary source of constituent mass is mixing with the formation as expected,
then the relative composition of drilling fluids should mirror that of the formation water. The extent
of mixing will depend on the distance drilled and the number of times the fluid is cycled through the
borehole. Horizontal wells tend to be drilled greater distances through the formation than vertical
wells. Thus, if constituent levels are higher in formation water from these wells, the same should be
true of the drilling fluid.
Available data indicate that the majority of dissolved constituent mass remains in solution during waste
management. There was no apparent enrichment of residual solids from the spent fluids. However, one
sample of solidified waste had disproportionately high radium activity that suggests contributions from
another source. It is possible that constituent mass from the fluids is retained on residual solids through
solidification, evaporation or another process. If so, this could result in much higher constituent levels
than predicted based on solids data. This represents a major source of uncertainty in the current data.
Drilling Solids
Drilling solids are a mixture of the wastes managed in reserve pits and tanks. Drill cuttings, which are
the rock and minerals that are ground up within the borehole and brought to the surface during well
installation, are typically the largest component of drilling solids. Cuttings are separated from the
drilling fluid at the ground surface, but may subsequently be mixed with spent drilling fluid and other
lower-volume wastes prior to disposal. The quantity and composition of the waste depends on the
conditions at the drilling site. Without information about the drilling and waste management practices
at a site, it is difficult to attribute measured constituent mass to a particular source. Thus, this discussion
focuses on drill cuttings, but considers mixed drilling solids where data are available.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-8

The composition of a single formation can vary considerably and deeper wells, like those necessary to
access hydrocarbon-bearing formations, inevitably traverse a number of distinct formations. As a result,
it can be difficult to define representative concentrations for cuttings. In recent years, the widespread
adoption of directional drilling has resulted in a substantial increase in the total volume of drill cuttings
generated. Depending on the diameter of the borehole, the depth to target formation and the lateral
distance drilled, the additional horizontal cuttings have been estimated to represent anywhere between
30 and 70% of the total volume generated (Johnson and Graney, 2015). The black shale in these cuttings
has been studied extensively in the literature. Therefore, this discussion focuses on the composition of
black shale, but considers cuttings from above the hydrocarbon formation where data are available.
5.2.1. Bulk Composition
Black shale is a type of sedimentary rock characterized by higher organic carbon that typically ranges
between 1% and 30% of the rock mass (Meyers and Mitterer, 1986). Extractable hydrocarbons in these
rocks originate from the decomposition of high-molecular weight organic matter known as kerogen
that decompose slowly at a specific range of temperatures and pressures found in some deep geological
formations. During decomposition, a variety of simple and complex organic compounds can form
alongside the economically-significant hydrocarbon deposits.
The inorganic fraction of black shale is composed of silicates and other minerals that form through
deposition and diagenesis (Ketris and Yudovich, 2009). EPA identified several studies that evaluated
the major mineral composition of black shales from California (Brumsack, 2005), Kentucky and Ohio
(Perkins et al., 2008), Mississippi (Rimmer, 2004), and Pennsylvania (Balashov et al., 2015; Phan et al.,
2015; Stuckman et al., 2015). Silicon dioxide (SiO2) present in minerals such as albite, illite and quartz
is the largest component of most samples, with content typically around 50% of the total mass. Other
major components are aluminum, barium, calcium and iron oxides, which each account for up to 20%
of the mass in individual samples. International studies that analyzed samples from China, Egypt, India,
Namibia, Peru and Poland all reported similar ranges (El-Anwar, 2016; Piszcz-Karaś et al. 2016).
Inorganic Elements
EPA identified three primary studies that measured inorganics in black shale formations. Ketris and
Yudovich (2009) assembled data on black shale from around the globe. Reported values reflect samples
grouped into separate distributions based on lithology (e.g., carbonate) and weighted based on the
frequency that each lithology was expected to occur. Chemak and Schreiber (2014) assembled data on
gas-producing black shale in the United States. Reported values reflect equally-weighted data from the
Antrim, Bakken, Eagle Ford, Marcellus, New Albany, Utica and/or Woodford formations. U.S. DOI
(2017) also assembled data on black shale from around the globe. Reported values reflect summary
statistics calculated from the raw data by EPA.6 The different approaches used to aggregate data
introduce some uncertainty and prevent further aggregation of the data from the different studies.
Therefore, the focus of this comparison is to identify major trends in the data and not to provide a

6) EPA used data analyzed with either non-destructive methods or digestion methods with hydrogen fluoride to ensure reported
values provide a best estimate of total mass. For most constituents, this was the majority of available data. The data were not
further weighted based on lithology or other metrics. Non-detect samples were omitted because the high detection limits relative
to the detected concentrations often overwhelmed summary statistics.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-9

definitive distribution for any element. The inter-quartile range was used for the comparisons because
it diminishes the effects of outliers that could skew higher percentiles and because these were the only
summary statistics provided by Ketris and Yudovich (2009). Table 5-5 provides a comparison of these
different data sources for elements reported in two or more sources.
Table 5-5. Inorganic Elements in Black Shale (mg/kg)
Constituent
Global
Black Shale1
Global
Black Shale2
U.S. Gas-Producing
Black Shale3
n 25th 50th 75th n 25th 50th 75th n 25th 50th 75th
Antimony 1,930 2.0 5.0 11 20,537 0.43 1.0 2.6 -- -- -- --
Arsenic 4,190 10 30 80 19,321 7.0 20 53 39 21 37 87
Barium 15,100 270 500 800 61,125 200 440 730 186 92 181 324
Beryllium 7,810 1.0 2.0 3.0 37,829 1.9 2.5 7.0 -- -- -- --
Cadmium 2,260 2.0 5.0 12 17,520 0.55 1.5 12 -- -- -- --
Chromium 21,900 50 96 160 56,921 30 70 100 199 54 84 119
Cobalt 21,000 10 19 30 51,878 5.2 10 18 169 5.0 14 21
Copper 25,740 35 70 150 45,659 20 50 100 -- -- -- --
Lead 20,520 10 21 40 49,534 15 27 46 -- -- -- --
Lithium 4,520 15 31 50 28,340 26 55 110 -- -- -- --
Manganese 19,600 200 400 800 50,150 110 252 500 -- -- -- --
Mercury 1,420 0.20 0.27 0.60 207 0.06 0.60 4.5 -- -- -- --
Molybdenum 18,480 6.0 20 60 35,685 7.0 15 40 303 27 74 116
Nickel 23,160 40 70 140 61,500 20 41 92 236 37 88 149
Selenium 1,650 3.0 8.7 30 8,589 1.4 3.1 8.0 -- -- -- --
Silver 9,000 0.40 1.0 2.4 19,619 0.45 1.0 3.0 -- -- -- --
Strontium 16,650 100 190 300 53,288 109 200 500 -- -- -- --
Thallium 2,710 0.50 2.0 10 4,512 0.60 0.96 4.3 -- -- -- --
Uranium 8,400 4.0 8.5 25 15,511 1.5 3.8 15 314 15 39 204
Vanadium 25,200 100 205 400 62,924 70 137 210 312 194 329 506
Zinc 13,300 60 130 300 47,115 51 105 200 187 64 108 340
1) Source: Ketris and Yudovich (2009)
2) Source: U.S. DOI (2017)
3) Source: Chermak and Schreiber (2014)
n = Number of Total Samples

The two global datasets are intended to reflect the same set of materials. Thus, any differences result
from variability among the formations sampled and the methods used to weight the data. Differences
are most pronounced for elements with the fewest data points (e.g., antimony, mercury, selenium). Yet
the considerable overlap between the distributions of many elements provides some confidence that
many of these elements have been adequately characterized.
Based on available data, many constituents in black shale are substantially higher than typical surface
soils reported in Geochemical and Mineralogical Data for Soils of the Conterminous United States (U.S.
DOI, 2013b), often by an order of magnitude or more. The metalliferous nature of black shale is well-
documented in the literature. Various studies have reported elevated levels of antimony, arsenic,
cadmium, chromium, copper, lead, mercury, molybdenum, nickel, selenium, silver, thallium, thorium,
uranium, vanadium and/or zinc (e.g., U.S. DOI, 1970, 1983; Ketris and Yudovich, 2009). These high
concentrations cannot be attributed to unique properties of any individual basin (Tourtelot, 1979; Scott,

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-10

2017). Instead, high levels result from the complex interplay of multiple factors, which include the rate
that organic matter deposited on the seafloor, the depth of the water column, both the extent and
duration of anoxic conditions, and local water chemistry. Under the anoxic conditions present during
the deposition of organic matter, redox-sensitive elements are sequestered from the water onto organic
matter or reduced sulfur (Arthur and Sageman, 1994; Chemak and Schreiber, 2014; Scott et al., 2017).
Many elements in gas-producing shale are similar to global shale, but a few are noticeably higher. One
key difference between these datasets is the amount of total organic carbon (TOC) present. Median
TOC in gas-producing samples is 9.7%, while the median in samples from U.S. DOI (2017) is 1.7%.
Constituents with an affinity for organic matter would be expected to concentrate in gas-producing
shales. This is true for uranium, the element with the greatest apparent increase relative to global shales.
The relationship between uranium and TOC can be so strong that gamma radiation has been used in
the field as a proxy for TOC during well surveys (Lüning and Kolonic, 2003) and black shale formations
were previously considered as potential sources of uranium ore (U.S. DOI, 1961). Other elements
measured in gas-producing shale known to associate with organic matter include chromium,
molybdenum, nickel, vanadium and zinc (Meyer and Robb, 1996; Wilde et al., 2004; Ross and Bustin,
2009; Scott et al., 2017). Moderate but consistent increases are seen in the data for molybdenum and
vanadium, but the remaining constituents are not readily distinguishable from global shale. The
absence of apparent differences might be attributed to other sources of these elements, particularly
reduced sulfur. Arsenic, chromium cobalt, nickel and zinc are also known to associate with sulfidic
minerals, such as pyrite (Meyer and Robb, 1996; Ross and Bustin, 2009; El-Anwar, 2016). The amount
of free hydrogen sulfide in the water column is not directly linked to the amount of organic carbon
that accumulates in a formation. Because higher concentrations of sulfur-bound elements may occur
in regions of both high and low organic carbon, similar concentrations are possible in all formations.
Thus, it is reasonable that all of the constituents associated with reduced sulfur are similar among
different sample sets.
The constituent with an apparent decrease in gas-producing shale is barium. Under anoxic conditions,
barium can remobilize and, as it diffuses upward and encounters waters with sulfate, reprecipitate as
barite (Henkel et al., 2012). This upward migration of barium can lead to greater stratification within
the black shale. As a result, barium enrichment can occur above black shale deposits to a greater degree
than other elements (Dean et al., 1984; Schijf, 2007; Henkel et al., 2012; Engle and Rowan, 2014). Thus,
barium is not necessarily depleted from the formation, but may be located in more concentrated lenses
within and above the shale. This spatial variability may contribute to observed differences, as samples
collected from horizontal cuttings or exposed rock outcrops have greater potential to miss more isolated
barite deposits.
Overall, the similarities between datasets indicate that global black shale data can provide a useful
estimate of potential concentrations for many elements in gas-producing black shale, though elements
with a strong affinity for organic matter may occur at even higher concentrations. The concentrations
in black shale may not be the same as the drilling solids that are ultimately disposed at the ground
surface. During drilling and subsequent storage, black shale will be blended with surrounding rock

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facies, which may dilute the higher inorganic concentrations found in the black shale. It is known that
many of the samples reflected in Table 5-5 were collected from drill cuttings (as opposed to targeted
outcrop samples) and so this blending is already reflected to some degree. The cuttings may also be
mixed with spent drilling fluid and other wastes that can alter the overall composition of the waste. To
better understand the extent to which these solids may differ from the initial cuttings, EPA reviewed
available data on drilling solids.
EPA identified a total of four studies that measured inorganic elements in drilling solids collected from
pits and tanks. Three drew samples from vertical wells in eleven states (Freeman and Deuel, 1984; API,
1987; U.S. EPA, 1987d). EPA did not identify information that could be used to further weight the data
to obtain a more representative national distribution, such as the volume of waste generated in each
state. Therefore, the data from each state were weighted equally. One study drew samples from
horizontal wells, both above and within the hydrocarbon formation, in one state (PADEP, 2016). The
horizontal well samples had been stabilized in preparation for land disposal. Table 5-6 presents the
50th and 90th percentile summary statistics of available data for inorganic elements in drilling solids.
Table 5-6. Inorganic Elements in Drilling Solids (mg/kg)
Constituent
Vertical Horizontal (Above) Horizontal (Within)
n 50th 90th n 50th 90th n 50th 90th
Antimony 2 / 11 2.5 4.3 14 / 38 1.8 26 14 / 18 18 28
Arsenic 11/11 2.1 7.8 38 / 38 11 17 18 / 18 26 38
Barium 11/11 2,650 6,000 38 / 38 3,215 16,620 18 / 18 82,050 220,600
Cadmium 3 / 11 0.25 2.7 38 / 38 2.1 16 18 / 18 37 70
Chromium 11/11 7.3 24 38 / 38 25 196 18 / 18 112 231
Cobalt 11/11 3.6 7 38 / 38 25 36 18 / 18 24 40
Copper 11/11 8.2 17 38 / 38 38 55 18 / 18 84 128
Lead 11/11 14 120 38 / 38 25 36 18 / 18 112 363
Manganese 11/11 125 190 38 / 38 554 619 18 / 18 235 413
Mercury 3 / 11 0.03 0.08 38 / 38 1.0 2.1 18 / 18 2.5 6.1
Molybdenum 6 / 11 1.2 2.9 38 / 38 4.0 11 18 / 18 50 112
Nickel 11/11 6.3 14 38 / 38 61 90 18 / 18 119 261
Silver 2 / 11 0.15 1.3 38 / 38 2.9 20 18 / 18 38 56
Strontium 11/11 68 260 38 / 38 283 1,124 18 / 18 1,423 6,184
Uranium 0 / 0 -- -- 38 / 38 3.7 6.6 18 / 18 19 49
Vanadium 11/11 8 11 38 / 38 121 209 18 / 18 12 173
Zinc 11/11 41 132 38 / 38 107 135 18 / 18 172 280
n = Number of Samples Detected / Total

Concentrations from vertical wells are generally lower than those from both sets of horizontal wells.
Some differences may arise because the vertical dataset consists primarily of single samples from various
states, which are unlikely to capture the full variability of any formation. The horizontal datasets show
there can be considerable variability within individual formations, but not enough to explain the order
of magnitude difference observed between the vertical and horizontal data. The more likely cause is
the different analytical methods used to measure constituent concentrations. Vertical samples were

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prepared for analysis with acid digestion (HNO3 + HCl),7 while horizontal samples were analyzed
directly with non-destructive methods. Non-destructive methods measure the entire constituent mass
within the sample matrix, while digestion methods measure the constituent mass that can be liberated
from the matrix with a combination of heat and acid (Gaudino et al., 2007). Some fraction of a
recalcitrant waste may not dissolve during digestion. This can result in an underestimation of elements
incorporated in the mineral lattice. These uncertainties limit the conclusions that can be drawn about
differences between vertical and horizontal wells. Yet, similar trends are seen in both datasets.
In all three sets of data, the median concentrations of barium are substantially higher than the black
shale reported in Table 5-5. The magnitude and frequency of higher concentrations indicates that a
majority of the barium does not originate from drill cuttings. The other large-volume waste typically
stored together with cuttings is drilling fluid. With modern equipment, fluid retention on cuttings is
typically below 15% by mass (U.S. EPA, 2000d). The dissolved concentrations of barium measured in
fluids are generally less than 1,800 mg/kg of water (Table 5-1).8 In addition, the range of concentrations
of barium and strontium measured in drilling fluid are similar, while those in pit solids are orders-of-
magnitude different. Thus, retention of drilling fluid alone does not account for disproportionately
high barium. The high ionic strength of the fluid also makes it unlikely that the high barium results
from selective sorption onto the surface of cuttings. Therefore, the most likely source of barium is
mixing of cuttings with barite that settles out of the drilling fluid.
Industry-grade barite is typically > 90% BaSO4 (U.S EPA, 1985). The amount of barite used depends on
the fluid density required to counteract increasing pressure within the formation and has been reported
to range anywhere from 15 to 62% of the total mass of the fluid (NRC, 1983). Only a small fraction of
barite is expected to adhere to cuttings during separation of fluids and cuttings at the surface, but
greater accumulation is possible if spent fluids are stored together with cuttings. At higher drilling fluid
densities, it would only require about 0.5 ft3 of drilling fluid mixed with each 1 ft3 of shale cuttings to
achieve the 90th percentile barium concentration measured in the horizontal drilling solids.9 At a
minimum, drilling fluid must be used in equal volumes to the cuttings removed in order to fill the void
in the borehole, though greater volumes are often be necessary. Thus, based solely on mass balance,
barite in spent drilling fluids could account for high barium concentrations in the final waste. This
accounts for the higher concentrations in horizontal solids relative to vertical solids, as higher water
densities may be required to drill under the greater pressure in these formations.
Although barite is predominantly barium sulfate, it can also contain inorganic contaminants present
alongside barite deposits. Previous analyses of barite have shown the additive can contain elevated
concentrations of arsenic, chromium, cadmium, copper, mercury, lead and zinc (NRC, 1983; Candler
et al., 1992; Neff, 2007). EPA previously concluded that veined deposits of barite tend to have higher

7) A mixture of nitric acid (HNO3) and hydrochloric acid (HCl) is commonly used to digest a range of materials, such as organic matter,
carbonates, phosphates and iron oxides. An example of a more aggressive acid is hydrofluoric acid (HF), which can be used to
digest silicates that comprise a large fraction of some drill cuttings.
8) Assumed fluid density of 1.0 kg/L representative of fresh water to provide a high-end concentration per unit mass.
9) Assumed fluid density of 2.1 kg/L and a shale density of 2.7 kg/L.

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Section 5: Waste Characterization 5-13

concentrations of these inorganic elements than bedded deposits (U.S. EPA, 1996).10 Veined deposits
are often found together with sulfide, rare-earth, gold and silver minerals (U.S. DOI, 1958). Many of
the contaminants reported in barite are elements that tend to associate with reduced sulfur, which are
the likely source of these other inorganics. The Agency previously identified concerns with the
potential toxicity of these inorganics to wildlife and, in 1996, finalized limits on the concentrations of
cadmium and mercury allowed in stock barite that can be discharged to open waters as part of the Oil
and Gas Extraction Point Source Category, Offshore Subcategory; Effluent Limitations Guidelines and
New Source Performance Standards (40 FR 10664). However, higher-concentration barite might still
be used in onshore drilling, as these wastes are not discharged directly to surface water. To better
understand the extent to which barite may affect the composition of drilling solids, EPA compared
concentrations in black shale (Table 5-4) and pit solids (Table 5-6). EPA found that the median
concentrations of antimony, cadmium, mercury, silver and strontium in horizontal drilling solids are
all considerably higher than the median values from the different black shale datasets. This indicates
that the addition of barite to drill cuttings might substantially increase concentrations of some
inorganic elements.
Organic Compounds
EPA identified a total of four studies that measured organic compounds in drilling waste. Two drew
samples of drilling solids from vertical wells in eleven states (API, 1987; U.S. EPA, 1987d). EPA did not
identify any information that could be used to further weight the data to obtain a more representative
national distribution, such as the volume of waste generated in each state. Therefore, the data from
each state were weighted equally. The remaining two studies drew samples of drill cuttings from
horizontal wells, both above and within the hydrocarbon formation, in two states (WVDEP, 2015;
Eitrheim et al., 2016). Table 5-7 presents the 50th and 90th percentile summary statistics of the
available data for organic compounds in drilling solids/cuttings.
Table 5-7. Organic Compounds in Drilling Solids (mg/kg)
Compound Vertical Solids Horizontal Cuttings (Above) Horizontal Cuttings (Within)
n 50th 90th n 50th 90th n 50th 90th
Benzene 11 / 11 0.03 0.59 2 / 3 20 96 3 / 5 773 1,870
Ethylbenzene 11 / 11 0.35 2.8 1 / 1 58 2 / 3 28 32
Toluene 11 / 11 1.1 3.1 1 / 1 37 3 / 3 58 62
Xylene 0 / 0 -- -- 1 / 1 390 3 / 3 390 438
N = Number of Samples Detected / Total

Concentrations in samples from horizontal wells both above and within the formation are substantially
higher than those from vertical wells. Horizontal wells tend to be drilled within formations with higher
organic content, which could account for the greater concentrations. However, there is additional
uncertainty introduced into this comparison by the fact that vertical samples reflect drilling solids and
the horizontal samples reflect drill cuttings. Concentrations in vertical samples may be diluted though
mixing with other wastes; however, the majority of the waste is still anticipated to be cuttings and so
dilution would not account for the orders-of-magnitude difference. The few samples of cuttings from

10) Veined deposits are those that fill cavities or fractures within a pre-existing rock formation. Bedded deposits are those that form
as a distinct depositional layer within a stratified formation.

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Section 5: Waste Characterization 5-14

above the horizontal formation have concentrations similar to or lower than from within the
formation. It is possible that these cuttings capture black shale that overlays the economically-
significant target formation. As a result of the sources of uncertainty, few conclusions can be drawn
without additional data.
Radioisotopes
EPA identified only one study that measured radioisotopes in drilling solids from one state (PADEP,
2016). Samples were collected from both above and within a horizontal formation. Each sample had
been stabilized in anticipation of land disposal, though the study did not specify how stabilization was
achieved. Table 5-8 presents the 50th and 90th percentile of the available data for radioisotopes in
drilling solids. To confirm the measured activities, some samples were directly measured with gamma
spectrometry and indirectly calculated based on measurement with X-ray fluorescence (XRF) and
natural isotope ratios. Where appropriate, both sets of measurements are presented for comparison.
Table 5-8. Radioisotopes in Stabilized Drilling Solids (pCi/g)
Isotope Analytical
Method
Horizontal (Above) Horizontal (Within)
n 50th 90th n 50th 90th
Uranium 235 γ-ray (235U) 8 / 38 0.08 0.15 12 / 18 0.18 0.39
Uranium 238 γ-ray (234Th) 20 / 38 0.80 1.6 12 / 18 1.2 3.4
XRF 37 / 37 1.3 2.2 18 / 18 6.3 17
Radium 226 γ-ray (226Ra) 38 / 38 2.1 3.8 17 / 18 3.8 9.9
Thorium 232* XRF 37 / 37 1.8 2.0 18 / 18 1.4 1.8
Radium 228 γ-ray (228Ac) 38 / 38 1.1 1.3 17 / 18 0.68 0.84
* PADEP (2016) reported 228Ra and 232Th activities that are nearly identical because values were based on ingrowth of
the same short-lived progeny (228Ac). Therefore, the 232Th data are not useful for comparison and is not presented.
n = Number of Samples Detected / Total

The 238U activities in samples calculated from XRF are often higher than those measured with gamma
spectrometry. This might indicate that the activities of this isotope measured by gamma spectrometry
are biased low. The low energy of 234Th (63.3 keV) has been reported to result in higher counting error
compared to other radioisotopes (U.S. DOE, 1981b). Yet some measured 226Ra activities are greater than
both measured and calculated 238U activities. As noted by PADEP (2016), 226Ra activities measured
directly by gamma spectroscopy can be biased high when radium and uranium are both present at
similar levels because current technology cannot fully distinguish the energy signatures of 226Ra and
235U. However, if 226Ra and 238U are in approximate equilibrium (i.e., no major outside source or sink of
radium), then there should be a relationship between 235U activity and the magnitude of excess 226Ra
measured in each sample. Even if activities measured with gamma spectroscopy are biased low, all of
the samples were measured with the same equipment and so should reflect a similar bias. Figure 5-3
presents graphs of vertical and horizontal samples based on the raw gamma measurements and
presented on the same scale for comparison.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-15

Figure 5-3: Relationship Between 235U and Excess 226Ra in Stabilized Drill Cuttings
There is a strong relationship between 235U activity and excess 226Ra in samples collected from within
the formation, which is similar to the relationship observed for solids from drilling fluid (Figure 5-2).
This indicates that the higher measured 226Ra activity can be attributed to interference from 235U. Thus,
radium and uranium are expected to be in approximate equilibrium in these samples. This aligns with
data from Eitrheim et al. (2016), which found 226Ra activity in two samples of drill cuttings from within
a shale formation to be similar to, but slightly lower than, 238U activity.11 Based on these data, it does
not appear that stabilization substantially changed the radioisotope composition of drill cuttings. The
drilling fluid from this formation is known to contain elevated radium, but these fluids may not have
been retained on the stabilized waste. No information is available on how solidification/stabilization
was achieved in these or other samples and so this represents a major source of uncertainty.
No such relationship is apparent for samples collected from above the shale formation. There are several
outliers of high radium, though removal of these samples only worsens the correlation. The excess
radium activity in remaining samples remains flat as 235U increases, which might indicate that radium
is depleted in these samples. In contrast, one sample of drill cuttings collected by Eitrheim et al. (2016)
from above a shale formation contained 226Ra activity similar to, but somewhat lower than, the 238U
activity. There is no single, clear explanation for the variable enrichment and depletion in these drilling
solids. Depletion may result from mixing of the cuttings with highly saline drilling fluid. Unlike black
shale, these rocks did not form in the presence of saline water, so it is possible that exposure to high
salinity may disrupt equilibrium and cause the release of radium to solution. Higher radium activities
may result from precipitation of barite out of solution as a result of quickly shifting water chemistry.
Samples with elevated radium all exhibit increased barium concentrations in proportion to activity,
while the remaining samples exhibit a flat relationship with barium. However, no information is
available on how solidification/stabilization was achieved in these or other samples and so this
represents a major source of uncertainty.

11) Eitrheim et al. (2016) measured 226Ra activity through the radon ingrowth method and so correction for interference from 235U
was not necessary.
R² = 0.05
0
4
8
12
16
0.0 0.2 0.4 0.6 0.8 1.0
22
6
Ra

-
23
8
U
(
p
C
i
/
g
)
235U (pCi/g)
Above Formation
R² = 0.70
0.0 0.2 0.4 0.6 0.8 1.0
235U (pCi/g)
Within Formation

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Section 5: Waste Characterization 5-16

5.2.2. Leachate
EPA identified three studies that measured both inorganic elements and organic compounds in leachate
from drilling solids from wells drilled with water-based fluids (API, 1987; U.S. EPA, 1987; LADNR,
1999). No data were identified for radioisotopes. Because of the limited amount of data available for
the different types of constituents, EPA did not break the discussion into separate sections. All available
samples were collected from vertical wells located in at least thirteen states. The majority of available
data are evenly distributed among the different states, but LADNR (1999) reported selected elements
for a greater number of samples from Louisiana. The same study also reported samples from wells
drilled with oil-based fluids. EPA combined the data without any weighting to compare wastes
generated with water- and oil-based fluids. Table 5-9 presents the 50th and 90th percentile of the
available data for both inorganic elements and organic compounds in leachate from drilling solids for
all constituents that were detected in at least half of samples.
Table 5-9. Constituent Levels in TCLP Leachate from Drilling Solids (mg/L)
Constituent
Vertical (Water-Based) Vertical (Oil-Based)
n 50th 90th n 50th 90th
Inorganic Elements
Aluminum 14 / 26 0.25 1.4 0 / 0 -- --
Barium 44 / 56 1.9 5.0 124 / 142 2.2 6.5
Boron 17 / 24 0.9 2.2 0 / 0 -- --
Cobalt 19 / 24 0.02 0.05 0 / 0 -- --
Iron 22 / 26 2.4 26 0 / 0 -- --
Lead 40 / 54 0.11 0.88 91 / 142 0.14 0.83
Manganese 26 / 26 2.8 5.5 0 / 0 -- --
Nickel 16 / 26 0.05 0.09 0 / 0 -- --
Strontium 24 / 24 3.3 15 0 / 0 -- --
Zinc 20 / 26 0.78 6.2 0 / 0 -- --
Organic Compounds
Toluene 22 / 30 0.03 0.83 0 / 0 -- --
n = Number of Samples Detected / Total

The available data provide only a few samples for most states and so are unlikely to capture the full
variability of individual formations. For example, none of the studies report the equilibrium pH of the
leachate. Alkaline wastes can counteract the fixed amount of acid used in the TCLP test increase the
pH of solution, which can greatly alter the solubility of some constituents. This makes it difficult to
determine what environmental conditions that these samples reflect. Despite the uncertainties,
available data allow a comparison of samples drilled with water and oil-based fluids because the
majority of samples are drawn from the same region. This comparison shows that both the median and
high-end concentrations of barium and lead are similar in magnitude. Limiting the comparison to only
samples from Louisiana does not alter this finding. Thus, there is no indication from available data that
the type of drilling fluid used substantially alters the leaching behavior of inorganics from the waste.
No comparisons could be conducted for any other constituents, including any organic compounds, as
a result of a large number of samples with high detection limits.

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5.2.3. Volatile Emissions
The presence of volatile organic compounds (e.g., benzene) and radioisotopes (e.g., radon) indicate
there is potential for releases to the surrounding air. However, EPA did not identify any studies that
measured volatile emissions of either type of constituent from drilling solids. Therefore, no conclusions
could be drawn about the magnitude or frequency of these releases.
5.2.4. Summary – Drilling Solids
There are a number of factors that determine the composition of black shale, which may include the
specific environmental conditions present at the time of formation (e.g., extent and duration of anoxia,
local water composition), the degree of subsequent evolution (e.g., thermal maturity of hydrocarbons,
extent of evaporation), and outside disturbances (e.g., uplift, intrusion from adjacent aquifers). All of
these factors result in a high degree of variability among and within source rock. Despite the numerous
sources of variability, there is substantial overlap in the concentrations of some elements among the
three datasets. This provides some confidence that the range of potential concentrations in black shale
has been adequately captured. However, the data also show the potential for higher concentrations of
elements with a strong affinity for organic carbon (e.g., molybdenum, uranium) in the subset of gas-
producing black shale. Drill cuttings are typically the largest volume waste in drilling solids and so
these data may provide a reasonable order-of-magnitude estimate of constituent levels in the associated
solids when direct measurements are not available.
The available data indicate that management of cuttings generated from both within and above the
formation may increase the total constituent mass in the waste. Comingling of drilling fluids with
cuttings at the ground surface can result in deposition of barite and other solids onto cuttings, which
can in turn increase concentrations of barium and other inorganics. There is currently no evidence that
adsorption of dissolved constituent mass from the drilling fluids onto the cuttings is a major source of
constituent mass. However, if drilling fluid is incorporated into the solidified/stabilized waste, it may
result in much higher constituent levels than predicted based on drilling solids alone. Limited data are
available on the extent to which this might occur in the field, which represents a major source of
uncertainty with the current data.
There are also limited data on the magnitude of releases from drill cuttings or drilling solids through
leachate and volatilization. Available studies do not provide key information, such as the equilibrium
pH of the measured samples. Because TCLP uses a fixed amount of buffer, wastes with high alkalinity
may shift the final pH of the leachate closer to neutral. The solubility of some constituents can change
dramatically over a small pH range and so this represents a major source of uncertainty. Thus, while
available data provide useful information about the solubility of some constituents, it is difficult to draw
conclusions about actual releases when the waste is disposed.
Produced Water
Produced water is any water drawn from the well as a byproduct of development and production. This
includes both the formation water and flowback of any water injected into the well to enhance
recovery. The volume of water generated can vary both by formation and individual well. Vertical

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Section 5: Waste Characterization 5-18

wells, which tend to be sited in more permeable formations, can be relatively dry at first. However, as
the pressure within the formation falls as a result of hydrocarbon withdrawal, formation water is more
likely to come to the surface together with the oil or gas. It has been reported that these fields can
produce more than five times the volume of water in later years (U.S. GAO, 2012). Later in the life of
the well, additional water may be injected into nearby wells to increase pressure within the formation
and displace remaining oil and gas (“waterflooding”). The injected water migrates through the
formation and is then drawn back up through the production well. Horizontal wells, which tend to be
sited in less-permeable formations, require water to be injected into the production well to liberate the
oil or gas trapped within the rocks prior to the start of production (“hydraulic fracturing”). The injected
water will return to the ground surface over a period of weeks to months. During this time, the
continued mixing of injected and formation waters results in produced water that transitions from
entirely injected water to entirely formation water. Additional water may be injected into a well
periodically over the lifetime of the well to further stimulate production.
Records of the chemical composition of formation waters are available as far back as the early twentieth
century (U.S. DOI, 1911). Initial interest in the composition of produced water was focused on the
potential commercial applications for the salt content and the potential to recover precious metals
(Rowan et al., 2015). As a result, early analyses were often limited to total dissolved solids (TDS) and
certain economically-significant metals. High salinity is a defining feature of produced water from
hydrocarbon formations. TDS in formation waters have been measured as high as 500,000 mg/L, over
ten times more saline than seawater. Sodium and chloride alone can account for greater than 90% of
the dissolved solids in the water (Schijf, 2007; U.S. DOI, 2017). Saline waters occur because the
formations have been subjected to elevated temperature and pressure, which cause the evaporation and
expulsion of water and further concentration of the remaining constituent mass. If a constituent
becomes so concentrated that it exceeds saturation in the remaining water, it may precipitate out in
solid deposits. It is possible that greater consolidation and evaporation in the dense formations that
require horizontal wells results in higher constituent levels from the concentration of mass into smaller
volumes of water. Therefore, EPA focused this review on potential differences in the wastes from
vertical and horizontal wells to determine whether and to what degree differences exist. Produced
water is assumed to be managed primarily as an aqueous waste and so EPA did not separately discuss
leachate from this waste.
5.3.1. Bulk Composition
Variable amounts of data are available for each formation, which makes it difficult to aggregate the
data in a representative way. To address this issue and to provide a more direct comparison with
previous evaluations, EPA mirrored the approach used in the 1987 Technical Support Document (U.S.
EPA, 1987d). EPA first grouped each state into zones based on similar geological formations, production
activities, and climates. Figure 5-4 presents the production zones used in this evaluation.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-19

Figure 5-4: Oil and Gas Production Zones in the United States (U.S. EPA, 1987d)
The full dataset was sampled probabilistically with data from each region weighted based on the
relative volumes of gross natural gas and crude oil produced in 2016 by each state from conventional
and unconventional formations (U.S. DOE, 2018c,d). All data from a given region was weighted equally
in each distribution. Some uncertainty is introduced by the fact that oil and gas production is not always
correlated with produced water generation. EPA identified several sources of data on produced water
volumes (API, 2000; U.S. DOE, 2009; GWPC, 2015). However, these data are often extrapolated from
older reports and do not capture recent increases in production from the spread of directional drilling.
In addition, although the amount of produced water generated in some high-producing states may be
lower on a per-well basis, the greater number of wells still results in higher overall generation in these
states. Therefore, weighting based on oil and gas production is considered reasonable for the purposes
of this evaluation.
Inorganic Elements
EPA identified a number of studies that measured concentrations of inorganic elements in produced
water from both vertical and horizontal wells. A summary of data collection efforts is provided in
Appendix B (Constituent Database). The summary statistics discussed in this section are based only on
the data for formation water. It is clear from the literature that formation water is the primary source
of inorganic constituent mass and, although flowback water will contain many of the same elements,
concentrations in formation water are typically higher (MSC, 2009; Ziemkiewicz and He, 2015).

Management of Exploration, Development and Production Wastes
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Flowback water can also be highly variable over time as a result of continued mixing with formation
water. Thus, formation water provides the most reliable comparison of concentrations. Table 5-10
presents the 50th and 90th percentile of the available data for inorganic elements in produced water
from vertical and horizontal wells. The amount of data available varies by constituent. To best capture
national variability, EPA limited the constituents presented below to those with data across multiple
regions of the country. EPA further refined this list by removing constituents that were measured
infrequently in high oil and gas-producing regions, which would skew summary statistics towards
those few samples. A far greater number of samples are available for vertical wells. This is because a
greater number of vertical wells have been drilled over time, which provided more opportunities to
collect samples.
Table 5-10. Inorganic Elements in Produced Water (mg/L)
Constituent
Vertical Horizontal
n 50th 90th n 50th 90th
Major Ions (mg/L)
Bicarbonate 36,060 / 36,060 380 1,731 50 / 52 289 1,281
Bromide 4,048 / 4,057 76 655 186 / 186 915 2,470
Calcium 39,512 / 39,512 1,760 13,846 267 / 267 4,430 20,100
Chloride 39,766 / 39,766 27,500 132,000 291 / 291 71,200 132,000
Magnesium 38,724 / 38,724 365 2,616 259 / 259 580 2,183
Potassium 15,844 / 15,844 141 1,270 205 / 206 326 1,030
Sodium 39,138 / 39,138 15,375 62,678 291 / 291 34,700 52,322
Sulfate 34,665 / 34,702 310 2,789 103 / 161 128 706
Trace Inorganics (mg/L)
Aluminum 154 / 185 0.25 7.4 21 / 42 0.21 10
Arsenic 51 / 65 0.01 0.20 -- -- --
Barium 1,579 / 1,593 4.8 171 220 / 256 13 6,470
Boron 1,369 / 1,370 39 115 192 / 195 21 46
Cadmium 58 / 75 0.01 0.02 -- -- --
Cobalt 52 / 67 0.005 0.02 -- -- --
Copper 226 / 254 0.015 1.0 -- -- --
Fluoride 429 / 438 1.5 7.0 -- -- --
Iron 2,212 / 2,244 5.5 63 249 / 250 63 185
Lead 147 / 195 0.05 0.5 -- -- --
Lithium 1,652 / 1,652 5.1 50 -- -- --
Manganese 1,322 / 1,338 0.78 8.6 214 / 223 2.5 14
Nickel 58 / 73 0.03 0.05 -- -- --
Strontium 2,732 / 2,733 60 1,240 252 / 252 737 3,840
Zinc 212 / 217 0.40 3.3 63 / 69 0.22 2.0
n = Number of Samples Detected / Total

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There is substantial overlap in the range of inorganic concentrations measured in produced water from
vertical and horizontal wells. Although concentrations in horizontal wells tend to be higher overall,
both well types can have similar high-end concentrations. It is possible the overlap of high-end
concentrations reflects saturation of certain elements in formation water. Chloride and sodium have
been reported to precipitate out as halite (NaCl) at the high concentrations reported in formation water
(PDCNR, 2010; Rowan et al., 2015). In contrast, bromide salts are more soluble than chloride salts and
so are less likely to precipitate at the comparatively low concentrations measured in formation water.
The data show that horizontal wells have higher median and high-end concentrations of bromide than
vertical wells. Another major difference between vertical and horizontal well concentrations is sulfate,
which tends to be found at lower concentrations in horizontal wells. This might be the result of
stronger reducing conditions in these formations. Reducing conditions can directly affect the solubility
of redox-sensitive elements, such as iron, and indirectly affect the solubility of elements that are limited
by the presence of sulfate, such as barium. A better understanding of such relationships may provide a
means to gauge the representativeness of available data and fill remaining data gaps.
If constituent relationships are based on geochemistry, rather than the unique properties of individual
formations or well types, then the relationship should not be isolated to a single formation or well type.
Therefore, EPA initially drew data from all well types (e.g., oil, coal bed methane, geothermal) to
identify potential relationships. The most common relationship reported in the literature is between
TDS and alkaline earth metals (e.g., barium, strontium). Because of the constant valence (+2), these
elements do not sorb as strongly to silicate surfaces as monovalent ions. Therefore, as the overall ionic
strength of groundwater increases, competition for binding sites could force barium and strontium into
solution (IAEA, 1990, 2014; Sturicho et al., 2001). EPA compared available data for halides and alkaline
earth metals to identify potential relationships.
Chloride was selected as a proxy for TDS in this comparison because it is one of the most commonly
reported analytes in produced water, is often the single largest contributors to TDS, and it eliminates
double counting of barium and strontium included in the TDS measurement. While chloride may not
directly compete with barium and strontium for binding sites, it provides a useful proxy for a range of
cations that can. There is potential for chloride precipitation to weaken any relationship at the highest
concentrations, though any relationships should still be apparent at lower concentrations. Although
other ions, such as bromine, are less likely to precipitate, the relative lack of data for these ions can
limit the conclusions that can be drawn from the comparisons. Figure 5-5 presents the best-fit
relationships between chloride and both barium (n = 3,540) and strontium (n = 4,927). All relationships
are graphed on a log scale. The red lines reflect the best-fit curves, while the black lines represent the
corresponding standard deviation.

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Figure 5-5: Relationships of Chloride with Barium and Strontium.
There is an apparent relationship between salinity and concentrations of both barium and strontium,
though it is stronger for strontium. These relationships exist despite compounding sources of variability
and uncertainty associated with data from different formations, well types, sample dates and analytical
methods. EPA considered whether the strength of the relationships could be unduly influenced by
extreme values. However, the available data are spread evenly over the reported interval and removal
of individual studies, well types and statistical outliers did not diminish the overall relationship. Based
on these findings, EPA reviewed the remaining dataset for other constituents that exhibit a relationship
with salinity. Of the constituents with sufficient data for comparison, only lithium showed a similarly
strong relationship (R2 = 0.78). Lithium is a monovalent cation of the same elemental group as potassium
and sodium. The presence of high concentrations of other alkali metals may result in competition that
forces more lithium into solution, similar to barium and strontium.
Although salinity may influence the solubility of these constituents, it is clearly not the only factor.
The standard deviation around each best-fit curve spans at least an order of magnitude. Other factors
such as pH and dissolved oxygen might account for some of the remaining variability, though the
relative importance of these other factors may change, depending on whether salinity dominates the
water chemistry. EPA reviewed the literature to identify any other relationships that might exist and
that could be evaluated with available data. The only relationships identified for barium and strontium
were with bicarbonate and sulfate (Engle and Rowan, 2014). The authors noted that barium
concentrations tend to be higher in sulfate-poor areas, while strontium concentrations tend be higher
in bicarbonate-poor areas. An inverse relationship is present because bicarbonate and sulfate react with
barium and strontium to form insoluble minerals that precipitate out of solution.
EPA conducted a direct comparison of barium and strontium as a function of bicarbonate and sulfate,
but found no apparent relationships. To understand the reason for the lack of a direct relationship, EPA
considered the fact that salinity is also an important factor in barium and strontium solubility. It is
possible the abundance of other ions in saline groundwater may limit the rate of chemical reactions,
resulting in greater retention of barium and strontium in solution. Therefore, EPA conducted an

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alternate comparison with both bicarbonate and sulfate expressed as a percentage of TDS. Figure 5-6
presents the best-fit relationships between bicarbonate and barium (n = 1,120) strontium (n = 1,659)
and between sulfate and barium (n = 2,595) and strontium (n = 3,689). All relationships are graphed on
a log scale. The red lines reflect the best-fit curves, while the black lines represent the corresponding
standard deviation.

Figure 5-6: Relationship of Bicarbonate and Sulfate with Barium and Strontium.
As expected, bicarbonate and sulfate (as a percent of TDS) have an inverse relationship with barium
and strontium. The strongest of these relationships are between barium and sulfate, which precipitate
as barite (BaSO4), and between strontium and bicarbonate, which precipitate as strontianite (SrCO3).
However, the same general trends are present for every combination. Differences in the strength of the
relationships are likely because formation of barite and strontianite is more thermodynamically
favorable and so exert greater control on dissolved concentrations. Barite has a lower solubility limit
than celestite (SrSO4), which can result in faster precipitation of barium in high-sulfate waters (Zhang
et al., 2014). EPA reviewed the remaining dataset for any other constituents that exhibit a relationship
with either bicarbonate or sulfate. Of the constituents with sufficient data for comparison, none were
found to have a similarly strong relationship.
To better understand the combined impacts of bicarbonate, chloride and sulfate on barium and
strontium, EPA conducted a multivariate regression analysis. For barium, the combination of chloride

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and sulfate was statistically significant and resulted in an R2 = 0.81, which is a better fit than chloride
(R2 = 0.64) or sulfate (R2 = 0.74) alone. For strontium, the combination of chloride, bicarbonate and
sulfate was statistically significant and resulted in an R2 = 0.86, which is a better fit than bicarbonate
(R2 = 0.73) alone, but is comparable to chloride (R2 = 0.86). EPA used the equation generated from this
analysis to probabilistically predict barium concentrations based on chloride and sulfate. Because far
more data are available for these major ions, this approach can provide a comparison for measured
barium data to gauge the representativeness of the available data. For each paired sample of chloride
and sulfate, a barium concentration was calculated based on the best-fit equation and then allowed to
vary based on the standard deviation. This process was repeated 100,000 times to ensure convergence
of the results. The resulting dataset was sampled probabilistically with data from each region weighted
based on the relative volumes of natural gas and crude oil produced in each state (U.S. DOE, 2018c,d).
All data from a given region was weighted equally in the distribution. Table 5-11 presents a comparison
of barium from vertical wells based on empirical and modeled data. The comparison is limited to
vertical wells because there are far fewer samples with paired chloride and sulfate compared to barium
for horizontal wells, which introduces uncertainty into the comparison.
Table 5-11. Comparison of Measured and Modeled Barium Concentrations (mg/L)
Constituent Measured Modeled
n 50th 90th n 50th 90th
Vertical 1,593 4.8 171 34,702 3.0 20
n = Number of Samples Measured/Modeled

There is general agreement between the median values of modeled and measured concentrations,
though there is a substantial difference between high-end values. This may indicate that the measured
data overestimate barium concentrations on a national-scale. Samples measured for both barium and
sulfate tend to have lower sulfate concentrations than the larger dataset that allow more barium to
remain in solution. It could also indicate that modeled concentrations underestimate concentrations to
some degree. Precipitation of halide and other minerals within the formation places an artificial ceiling
on modeled barium concentrations. Therefore, EPA concludes that the measured and modeled data can
provide reasonable bounds on the potential barium concentrations in produced water. Future data
collection and analysis can further refine this relationship and improve predictions.
Organic Compounds
EPA identified several studies that analyzed organics in produced water from vertical and horizontal
wells. A summary of data collection efforts is provided in Appendix B (Constituent Database). The full
dataset for organic compounds was sampled probabilistically with data from each region weighted
based on the relative volumes of natural gas and crude oil produced in each state (U.S. DOE, 2018c,d),
the same as previously described for inorganic elements. All data from a given region were weighted
equally in each distribution. The only compound with sufficient data to calculate summary statistics is
benzene. The only well type with sufficient data are vertical wells. Table 5-12 presents the 50th and
90th percentile of the available data for benzene in produced water from vertical wells.

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Table 5-12. Organic Compounds in Produced Water (mg/L)
Constituent Vertical
n 50th 90th
Benzene 27 / 32 0.23 4.9
n = Number of Samples Detected / Total

Although the most data are available for benzene, there are many other organic compounds that have
been identified in produced water. As many as 1,400 to 2,500 compounds have been tentatively
reported based on chromatogram energy peaks, though less than half this amount have been identified
with confidence (Hoelzer et al., 2016; Khan et al. 2016). Many of these may be isomers, acids,
substitutions and other variations of previously identified compounds. EPA identified eleven studies
that analyzed for organics in produced water.12 However, some of these studies only report whether a
compound was detected and not the associated concentrations. These studies analyzed samples drawn
from several unnamed conventional formations, as well as the Marcellus, Eagle Ford and Barnett shales.
The 1987 Technical Support Document (U.S. EPA, 1987d) analyzed a total of 444 organic compounds
in produced water from vertical wells that included a range of volatile (n = 55), semi-volatile (n = 176),
dioxin and dioxin-like compounds (n = 136) and pesticides (n = 77). Many of the compounds were
below detection limits in all samples. The types of compounds detected most frequently include
aliphatic hydrocarbons (i.e., C12 – 30), ketones (i.e., methyl isobutyl ketone, isophorone), alcohols
(i.e., terpineol), phthalates [i.e., bis(2-ethylhexyl) phthalate], simple aromatic hydrocarbons
(i.e., benzene, ethylbenzene, phenol and methylated substitutions, toluene), polycyclic aromatic
hydrocarbons [i.e., 2-(methylthio)benzothiazole, dibenzothiophene, naphthalene and methylated
substitutions] and other volatile organics (i.e., carbon disulfide). The compounds measured at the
highest concentrations tended to be aliphatic and simple aromatic hydrocarbons, which are common
components of crude oil. A concurrent study conducted by the American Petroleum Institute identified
similar concentrations of many constituents (API, 1987).
Many of the same compounds reported in U.S. EPA (1987d) were also detected in more recent samples
from vertical wells (MSC, 2009; Maguire-Boyle and Barron; 2014; Orem et al., 2014; Ziemkiewicz and
He, 2015; Khan et al., 2016). These studies reported several additional compounds measured for, but
not detected, in the 1987 studies. Examples include phthalates (e.g., di-n-octyl-phthalate), simple
aromatic hydrocarbons (e.g., benzyl alcohol), polycyclic aromatic hydrocarbons (e.g., fluorene,
phenanthrene, pyrene, pyridine) and other volatile compounds (e.g., bromoform, chloroform).
Concentrations of these additional constituents were generally low and may be the result of improved
detection limits. It is also possible that some of these compounds were added to injected water as a
solvent, biocide, lubricant, tracer or other purpose. The attribution of compounds is complicated by
uneven reporting of usage and the fact that some compounds added to injected water are the same as
those that occur naturally in the formation. For example, naphthalene was reported in 19% of
FracFocus 1.0 disclosures (U.S. EPA, 2016a). The practice of recycling produced water as the base fluid
for hydraulic fracturing can also introduce naturally-occurring organics into the fluid. Furthermore,

12) API, 1987; U.S. EPA, 1987; Hayes, 2009; Maguire-Boyle and Barron; 2014; Orem et al., 2014; Abualfraj et al., 2014; Ziemkiewicz and
He, 2015; Hoelzer et al., 2016; Khan et al., 2016, U.S. EPA, 2016c; USGS, 2016

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the high temperature, pressure and salinity found in many hydrocarbon formations has the potential
to transform the compounds through processes such as methylation and halogenation (Hoelzer et al.,
2016).
MSC (2009), Orem et al. (2014) and Ziemkiewicz and He (2015) reported concentrations of organic
compounds in the water at different stages of production. Compounds detected in water used as a base
for hydraulic fracturing fluid include acetone, bromoform, naphthalene, trimethylbenzene and xylene.
This indicates that the base is recycled produced water and so it is not clear if the detected compounds
originate from the formation or additives. Compounds that were detected in the prepared fracturing
fluid and that decreased over the first 20 days of production include bis(2-chloroethyl)ether, carbon
disulfide and methylnaphthalene. The lack of contribution from the formation indicates that these
compounds originate primarily from additives. Although 20 days is a relatively short timeframe relative
to the lifespan of a well, it is also typically when the largest volumes of produced water are generated
(U.S. EPA, 2016a). Therefore, the presence of these organic compounds may still be environmentally
significant.
The organic compounds reported in produced water vary widely in solubility and hydrophobicity.
Although potential health effect endpoints have been identified for some compounds, toxicity values
have not yet been developed for many, particularly the various derivatives and degradation products
(U.S. EPA, 2016a). Therefore, it is difficult to quantify the magnitude of potential risks associated with
releases of these compounds to the environment.
Radioisotopes
EPA identified several sources that analyzed for radioisotopes in produced water from both vertical
and horizontal wells. A summary of the data collection efforts is provided in Appendix B (Constituent
Database). The full dataset for radioisotopes was sampled probabilistically with data from each region
weighted based on the relative volumes of natural gas and crude oil produced in each state (U.S. DOE,
2018c,d), the same as previously described for inorganic elements. All data from a given region were
weighted equally in each distribution. The only isotope with sufficient data for summary statistics was
226Ra. Table 5-13 presents the 50th and 90th percentile of the available data for 226Ra in produced water
from vertical and horizontal wells. EPA also considered how reported sample errors could affect
summary statistics, but the addition of error measurements to reported activities had negligible impact
on the calculated summary statistics. Therefore, EPA only summarized reported activities in this table.
Table 5-13. Radioisotopes in Produced Water (pCi/L)
Constituent Vertical Horizontal
n 50th 90th n 50th 90th
Radium-226 127 / 127 145 1,060 69 / 69 2,300 4,470
n = Number of Samples Detected / Total

This comparison indicates that both high-end and median activities of 226Ra are higher in horizontal
wells. These differences mirror those observed for barium and strontium. Radium is also an alkaline
earth metal and so similar behavior is expected. Multiple studies have reported relationships between
salinity and radium, but noted that the slope of the relationship can vary among formations (ILGS,

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1983; Chermak and Schreiber, 2014). This aligns with previous findings that salinity is not the sole
factor that influences barium and strontium solubility. EPA considered both chloride and bromide in
the comparison due to similar amounts of paired data available. Figure 5-7 presents the relationships
for 226Ra with chloride (n = 459) and bromide (n = 242). All relationships are graphed on a log scale.
The red lines reflect the best-fit curves, while the black lines represent the corresponding standard
deviation.

Figure 5-7: Relationship of Chloride and Bromide with Radium-226.
There is a clear relationship between salinity and radium activity. Both chloride and bromide provide
a good fit. Although bromide provides a slightly better fit, this may be influenced by fewer data points
clustered closer to the highest and lowest values. EPA also compared radium activity with bicarbonate
and sulfate (as a percent of TDS), but did not identify any similarly strong relationships. This may be
because the range of radium concentrations reported in literature all fall below the solubility limit of
radium minerals, such as radium sulfate (Sturchio et al., 2001; SKB, 2008). The highest reported activity
of 27,000 pCi/L corresponds to a dissolved concentration of only 0.027 μg/L. Instead, radium loss is
driven primarily by co-precipitation with barium and strontium, which are part of the same group of
alkaline earth metals (Zhang et al., 2014). It is possible that a relationship with bicarbonate and/or
sulfate does exist; weak inverse trends can be seen in plotted data. Yet such an indirect relationship
would be more complex than those identified for barium or strontium and may require other types of
data or different handling of existing data to identify.
The majority of available studies sampled only for 226Ra because the longer half-life of this isotope
makes it more persistent in the environment. Omission of 228Ra can substantially underestimate total
radium activity in samples, which can result in an underestimation of risk and may skew relationships
present in the data. Therefore, EPA explored both whether it is possible to predict 228Ra activity based
on measured 226Ra activity and how inclusion of both isotopes may affect the relationship with salinity.
The available literature is inconsistent on whether a relationship exists between radium isotopes. Some
studies report a strong correlation between the two isotopes (Fisher, 1998), while others found a more
moderate relationship (U.S. DOE, 2004) or none at all (ILGS, 1983). Figure 5-8 presents the relationship
between 226Ra and 228Ra (n = 120) and between chloride and 226+228Ra (n = 120). All relationships are

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graphed on a log scale. The red line represents the best-fit curve, while the black lines represent the
corresponding standard deviation.

Figure 5-8: Relationships of Radium-226 and Radium-228.
This left graph shows a strong relationship between the activities of different radium isotopes. This is
reasonable, given that all isotopes of radium will behave the same chemically. Anything that increases
the solubility of 226Ra should have a similar effect for 228Ra. However, as 226Ra activity increases, 228Ra
tends to decrease as a fraction of the total radium. Some studies have reported that the ratio of radium
in produced water mirrors that of the parent rock (Sturicho et al., 2001). The decreasing radium ratio
may reflect the greater potential for uranium to accumulate in the high-organic rock in hydrocarbon-
bearing formations. The best-fit equation indicates that the average 228Ra/226Ra ratio will range between
0.3 and 0.4, based on the 50th and 90th percentile of measured 226Ra activity. This compares well with
previous estimates around 0.3 (U.S. EPA, 1993; Bernhardt et al., 1996). Inclusion of both isotopes shown
in the right graph results in a noticeable shift in the best-fit line toward higher activities (e.g., 230 vs
98 pCi/L at 10,000 mg/L Cl). The addition of radium isotopes also results in a better fit though, again,
this may be influenced by fewer data points clustered closer to the highest and lowest values.
To better understand the impact of chloride and bromide on dissolved 226Ra activity, EPA conducted a
multivariate regression analysis. This analysis was only conducted for 226Ra because it is the only isotope
with sufficient measured data to allow a comparison. EPA used the equation generated from the
regression analyses to probabilistically predict 226Ra activity based on measured chloride and bromide
concentrations. For each sample of chloride or bromide, a radium activity was calculated based on the
best-fit equation and then allowed to vary based on the standard deviation. This process was repeated
a total of 100,000 times to ensure convergence of the results. The resulting dataset was then sampled
probabilistically with data from each region weighted based on the relative volumes of natural gas and
crude oil produced in each state (U.S. DOE, 2018c,d). Data from a given region were weighted equally
in each distribution. Table 5-14 presents a comparison of activities from empirical and modeled data.

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Table 5-14. Comparison of Measured and Modeled Radium-226 Activities (pCi/L)
Constituent Sampled Modeled (Cl) Modeled (Br)
n 50th 90th n 50th 90th n 50th 90th
Vertical 127 145 1,060 39,766 187 565 4,057 145 867
Horizontal 69 2,300 4,470 291 341 587 186 1,095 2,397
n = Number of Samples Measured/Modeled

There is overlap among the three datasets, though chloride and bromide both predict lower activities
than reported in the literature. This could be because many studies tend to focus on individual wells or
formations already known to have elevated radioactivity, which can skew the dataset higher.
Predictions with chloride result in the lowest activities, similar to barium. Precipitation of halide and
other minerals within the formation could place an artificial ceiling on modeled radium activities.
Despite these uncertainties, the predicted activities generally agree with the overall magnitude of
activities reported in the literature. Therefore, EPA concludes that the combination of measured and
modeled data can provide reasonable bounds on estimates of potential radioactivity in produced water.
Future data collection and analysis can further refine these relationships and improve predictions.
5.3.2. Volatile Emissions
The presence of volatile organic compounds (e.g., benzene) and radioisotopes (e.g., radon) indicate
there is potential for releases to the surrounding air. However, EPA did not identify any sources that
analyzed for volatile emissions of organic or inorganic constituents from produced water. Therefore,
no conclusions can be drawn about the magnitude or frequency of these releases.
5.3.3. Summary – Produced Water
Based on the available data, EPA concludes that similar concentrations of some inorganics and
radionuclides are possible in produced water generated from vertical and horizontal wells. As a result,
the magnitude of releases to the environment or deposition to downgradient wastes (e.g., scale and
production sludge) can be similar. The extent to which constituent concentrations in produced water
are related to the permeability of the formation is not clear at this time because the available literature
often does not provide this information about the sampled formations. However, the relationships
identified from the literature indicate local geochemistry is more important than the specific well type
in determining the magnitude of dissolved concentrations in the produced water.
The relationships identified from the literature cannot be used to predict the exact concentration in
the produced water from any individual well. There are too many remaining sources of variability that
result in a range of potential concentrations that extend an order-of-magnitude or more. However,
these relationships may provide probabilistic distributions that can be used to predict likely
concentrations in an area. Further investigation can refine known relationships and may also identify
additional ones.
It is clear that there are also numerous organic compounds that may be present in produced water.
However, insufficient data are available to compare these organic concentrations from vertical and
horizontal wells. The most commonly detected organic compounds are commonly associated with
hydrocarbons (e.g., benzene, toluene), but these compounds do not always originate from the

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formation. Source attribution is complicated by inconsistent reporting on additive usage in hydraulic
fracturing fluids, chemical transformation within the subsurface, and the increasing practice of
recycling produced water back into hydraulic fracturing fluid. Even when the structures of the organic
compounds present are known, there may not yet be data on the potential mobility and toxicity.
Without these data, the potential risks associated with releases to the environment cannot be
quantitatively evaluated.
Pipe Scale
Pipe scale is the hard precipitate that accumulates on the walls of pipes and other equipment. There
are multiple types of scale that can form, which depend on the minerals that are at or near saturation
in the produced water. The scale that forms can occur as a single compound or as an amalgamation of
similar compounds. The most common types of scale are carbonates (e.g., CaCO3), halides (e.g., NaCl),
silicates (e.g., Fe2SiO4), sulfates (e.g., SrSO4) and sulfides (eg., PbS). Sulfate scale is the dominant type
associated with oil and gas wells. There are two main causes of sulfate scale. The first is mixing of
incompatible waters. When water injected into the well to enhance recovery has high sulfate levels
relative to the formation water, then scale may precipitate instantaneously and in high volume. In
extreme cases, this type of scale formation has completely clogged wells in under a day (Crabtree et al.,
1998). The other cause is changes in mineral solubility as a result of the decreasing pressure and
temperature of water as it is brought to the surface. Generally, minerals are about half as soluble at
77 °F (25 °C) than at 203 °F (95 °C), and about half as soluble at atmospheric pressure than at 7,000 psi
(48 MPa), regardless of the initial concentration (Oddo and Thomson, 1994; Crabtree et al., 1998). This
type of accumulation of scale can be gradual and might not be detected until the equipment is taken
out of commission (Collins, 1975; Kan and Tomson, 2010).
Sulfate scale that forms on equipment surfaces is highly resistant to removal through either mechanical
or chemical means. Scale inhibitors can be mixed in the injected water to reduce or eliminate scale
formation either by increasing the solubility of the compound or by disrupting the ability of the scale
to affix or grow on equipment surfaces (Crabtree et al., 1998). These additives can eliminate scale
formation when the water is slightly oversaturated, but it may not be possible to entirely prevent scale
formation when water is highly oversaturated (Kan and Tomson, 2010). Some of the scale may instead
precipitate out as independent minerals or onto suspended solids before settling out of solution further
down the production stream. The remainder of this section focuses on scale that forms as relatively
homogenous deposits on equipment surfaces. Scale deposited in sludge further along the production
stream is discussed in a subsequent section of this document.
5.4.1. Bulk Content
Common types of sulfate scale associated with oil and gas wells are anhydrite (CaSO4), barite (BaSO4)
and celestite (SrSO4). The amount of each that precipitates depends on the relative concentrations and
solubility of these minerals in the produced water. Due to the extremely low solubility of barite, it is
often the dominant mineral (Crabtree et al., 1998; Zhang et al., 2014). Scale samples collected from

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Texas had an average composition of 31% Fe, 14% Ba, 2% Sr and 1% Ca (TXBEG, 1995).13 Scale samples
from Brazil had an average composition of 40% BaO, 9% SrO and only 3% FeO (Godoy and Petinatti
da Cruz, 2003).14
Radium does not form an independent mineral phase because dissolved concentrations are orders-of-
magnitude below saturation, even at the highest measured activities (Sturchio et al., 2001; SKB, 2008).
However, radium will readily co-precipitate with barite by substituting for barium in the crystal lattice
(Zhang et al., 2014). As a result, radium can precipitate regardless of the amount dissolved in water. A
review of the literature indicates that radium is the primary constituent of concern associated with this
waste stream. Table 5-15 presents a summary of radium content in pipe scale from different states. EPA
identified thirteen studies that provide data from nine states. EPA did not identify any data of the
volume of scale generated in these or other states. As a result of this and differences in both sample size
and reported activities among the studies, EPA did not attempt to further aggregate the data.
Table 5-15. Radioisotopes in Scale (pCi/g)
State Well Type
Ra226 Ra228
n 50th 90th n 50th 90th
California Vertical 22 / 22 9.3 512 22 / 22 15 501
Kentucky Vertical 13 / 13 1,711 2,164 10 / 10 45 55
Louisiana Vertical 9 / 9 360 1,226 1 / 1 120
Michigan Vertical 11 / 12 539 1,466 11 / 12 60 111
New York Vertical 7 / 7 1.0 5.2 4 / 6 0.60 2.5
North Dakota Horizontal 38 / 40 148 1,434 38 / 40 76 599
Oklahoma Vertical 8 / 8 1,715 1,851 1 / 8 0.05 4.0
Pennsylvania Vertical 2 / 2 2.0 2.6 2 / 2 1.2 1.3
Texas Vertical 37 / 37 895 2,436 37 / 37 1,295 3,880
n = Number of Samples Detected / Total

Both high-end and median scale activity are elevated in multiple states. Most studies reported instances
of combined radium activities far greater than the upper bound of 4.2 pCi/g measured in surface soil
(U.S. DOE, 1981a). Thus, there is clear potential for high activities in this waste. However, it is not
possible to define a representative distribution of potential activities with available data because of the
approach used to select sample locations. Some studies conducted an initial survey of operating
equipment with hand-held instruments to guide sample collection toward areas of elevated activity.
This preferential sampling of hotspots is likely to overestimate the prevalence of higher activities. A
survey overseen by API concluded that between 10 and 30% of oil and gas wells in the United States
produce radium-enriched scale in pipes and other equipment (API, 1989; Rood et al. 1998). However,
the basis for that estimate is measurements taken around the external surface of the equipment. As a
result, this estimate does not account for downhole accumulations that may occur over time.
Furthermore, measurements on the external surface of equipment may underestimate the magnitude
of radioactivity present due to shielding of gamma radiation. Based on the work of Bernhardt et al.

13) If all Ba and Sr are present as sulfates, these minerals would account for 25% and 4% of the total mass, respectively.
14) If all Ba and Sr are present as sulfates, these minerals would account for 60% and 15% of the total mass, respectively.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-32

(1996), a steel pipe with internal activity as high as 60 pCi/g 226Ra could result in external measurements
comparable to background.15 However, greater exposures are possible when the scale is disturbed
during management and disposal.
Although relatively low activities were reported for New York and Pennsylvania, the same studies
measured produced water activities above 1,000 pCi/L 226Ra. Therefore, there is ample radium available
to precipitate if conditions are favorable. The measured concentrations of barium and sulfate are similar
to those in states with higher scale activity and overlap with solubility limits modeled under standard
environmental conditions (Langmuir and Melchior, 1985; SKB, 2008). This indicates that radium may
precipitate gradually over time. It is possible that the small number of samples reported by these studies
missed areas of higher activity. Recent studies have reported favorable conditions for scale formation
from the horizontal wells in these states (Blauch et al., 2009; Engle and Rowan, 2014).
Many of the studies reported activities for both 228Ra and 226Ra in scale. The isotope ratio of 228Ra/226Ra
in freshly deposited scale should mirror that of the produced water because different isotopes of the
same element exhibit the same chemical behavior. However, the isotope ratio of scale will decrease
over time. The shorter half-life of 228Ra (i.e., 5.7 years) compared to 226Ra (i.e., 1,600 years) results in
the depletion of 228Ra in older samples (Fisher and Hammond, 1994). Few studies reported the age of
scale samples. In cases of gradual accumulation, it is often unknown how long scale is present in a pipe
before it is removed from service and how long after that the samples have been stored in pipe yards
or drums awaiting disposal. One study that measured 214Pb and 214Bi found these radioisotopes to be in
approximate equilibrium with 226Ra, but found 210Pb was a factor of four lower (Landsberger et al.,
2016). If decay of 226Ra were the only source of 210Pb (i.e., no independent precipitation), the age of this
scale would be at least 10 years old. Another study estimated the age of scale found in a pipe yard to be
nearly 30 years old (Zielinski et al., 2000). This is another source of uncertainty when defining
representative activities at the time of disposal.
5.4.2. Leachate
EPA identified few studies that evaluated the leaching behavior of scale from oil and gas wells. Studies
of similar scale from uranium mine tailings reported barite to be insoluble under typical environmental
conditions, but more soluble under reducing conditions (Fedorak et al., 1986; Huck and Anderson,
1982; Huck et al., 1989; McCready et al., 1980). Chemical reduction of sulfate is often a slow process,
but biologically-mediated reduction can occur at a much faster pace when conditions are favorable.
Bacteria capable of reducing sulfates occur naturally in the soil, though the high concentrations of
inorganic elements and organic compounds in produced water might inhibit bacterial growth (Phillips
et al., 2001; U.S. DOE, 2004). As a result, the two available studies of oilfield scale focused on samples
that had been incubated with soil or bacterial cultures to enhance releases. Phillips et al. (2001)
incubated a scale sample of 1,300 pCi/g 226Ra with and without bacteria isolated from production pit
for ten months. The presence of sulfate-reducing bacteria increased the dissolved activity from 0.54 to

15) 60 pCi/g results in an estimated exposure rate around 7 microroentgens (μR)/hr. API (1989) reported median background
exposure rates across the United States ranging from 5 to 9 μR/hr. MIDNR/DPH (1991) reported background rates in Michigan
between 3 and 7 μR/hr, while U.S. DOI (1997b) reported rates in Kentucky between 7 and 8 μR/hr.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-33

14.9 pCi/L 226Ra. DOE (2004) incubated scale samples with soil collected from the sample area for two
weeks. However, this study reported the leachate activity as a percentage of the original bulk activity.
Without additional information on both the bulk activity of the sample and the liquid-to-solid ratio of
the leaching test, these data cannot be converted to a comparable dissolved activity. Discussion solely
in percentages can also give the misleading impression that the leachate activity is low. For example,
the activity reported by Phillips et al. (2001) was equal to only 0.04% of the total mass.
Neither of the studies reported the final pH of the leachate. Therefore, there is uncertainty about the
environmental conditions these samples reflect. This uncertainty may be minor, as geochemical
modeling indicates that leaching from scale is independent of pH outside of extremely acidic (pH < 2)
or basic (pH > 12) conditions (Huck et al., 1989). Yet shifts in pH could also inhibit the growth of
bacteria that drive barite reduction. In addition, there are no data available on how leaching from the
scale might change over time. Because the bacteria break down a fundamental component of the scale
matrix as a source of energy, it may be reasonable to assume a substantial fraction of the radium could
eventually be released.
Another source of uncertainty in the available data are that neither study measured releases of both
226Ra and 228Ra from scale. Therefore, both studies underestimate the magnitude of radium leached to
some degree. Phillips et al. (2001) reported the activity of both isotopes in the scale sample, but only
the leached 226Ra activity. Under the assumption that the two isotopes are equally distributed in the
scale matrix and thus have a similar potential to leach, total activity in the presence of sulfate-reducing
bacteria would fall closer to 27.2 pCi/L 226+228Ra.
5.4.3. Air Emissions
Radon is the only member of the uranium and thorium decay chains that exists as a gas at room
temperature. Two isotopes of radon, 222Rn and 220Rn, are created by the direct decay of 226Ra and 228Ra,
respectively. The majority of studies do not analyze for 220Rn because the much shorter half-life
(i.e., 55 seconds) limits potential exposures, particularly when the gas must first migrate through soil
or other porous media. Even for the longer lived 222Rn (i.e., 3.8 days), some fraction of the gas will not
escape into the atmosphere. Therefore, releases are frequently reported in terms of the relative amount
of radon that does escape (i.e., emanation fraction). There is no correlation between the activity of this
waste and the emanation fraction. Releases are controlled by the physical structure of the waste, rather
than the overall activity, so these measurements can be used together with the activity in other samples
to estimate potential emission rates.
EPA identified two studies that analyzed samples collected from Kentucky, Louisiana, Michigan,
Oklahoma and Texas (Wilson and Scott, 1992; U.S. DOE, 1999b). Because the emanation fraction is not
a function of activity, EPA combined data from the different states. The data are instead broken out
based on the integrity of the scale samples. Some studies have reported substantial differences between
the larger samples of intact scale still attached to the pipe and the smaller disturbed samples collected
from the ground and drums. Table 5-16 presents the 50th and 90th percentile of the available data for
radon emanation from intact and disturbed pipe scale.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-34

Table 5-16. Radon Emanation Fraction from Scale
Isotope
Emanation Fraction
n 50th 90th
Intact Scale 31 / 31 0.039 0.095
Disturbed Scale 18 / 18 0.135 0.239
n = Number of Samples Detected / Total

As reported in the literature, available data show that samples of disturbed scale tend to have higher
emanation fractions. Because emanation is limited by the rate at which radon can migrate out of the
scale, it is reasonable that scale with a higher surface area to volume ratio would also have higher
relative emanation (U.S. DOE, 1999b; White and Rood, 2000; Phillips et al., 2001). The density of intact
barite deposits on equipment is estimated to be around 2.6 g/cm3, which is comparable to that of many
rocks (U.S. DOE, 1996). The emanation fraction of this intact scale is comparable to undisturbed soil
(Rood et al., 1998). In contrast, disturbed scale has emanation fractions comparable to uranium mine
tailings (White and Rood, 2000). There is little overlap in the data for these two types of samples.
Therefore, use of lower emanation fractions to estimate releases from scale that is separated from the
pipe or otherwise disturbed during disposal is likely to underestimate potential exposures.
5.4.4. Summary – Pipe Scale
Available data show that pipe scale can form on oil and gas equipment in any region of the country.
Radium activities in measured and modeled produced water from both vertical and horizontal wells
are high enough to cause the activities measured in pipe scale. However, high dissolved radium activity
alone does not guarantee that high-activity scale will form. Radium typically precipitates along with
sulfate or carbonate minerals, so the rate and extent of precipitation depends on the chemistry of the
formation. When scale forms on equipment surfaces, it may accumulate slowly and not be apparent
until after the equipment has been taken out of service. Use of scale inhibitors can reduce the total
volume that adheres on the equipment surfaces over time, but inhibitors may not completely prevent
scale formation. If inhibitors only delay deposition, then greater radium accumulation may occur in
downgradient wastes, such as production sludge.
Pipe scale is anticipated to be managed independently from other wastes because of the considerable
effort required to physically or chemically dislodge the scale from equipment surfaces. However, the
Agency identified little documentation on where pipe scale is currently disposed. The radium activities
reported in the literature would pose additional management challenges, as the activities are frequently
higher than the limits allowed in many landfills. It is important to note that the available data may be
biased toward higher activities because some studies used hand-held instruments to guide sample
collection toward areas of elevated activity. As a result, a greater fraction of the scale generated may
have lower activities than predicted by the current dataset. However, remaining scale may also have
elevated activities that are shielded from surface measurement by the metallic equipment. This
represents a major source of uncertainty in the current data.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-35

Production Sludge
Production sludge (hereafter referred to simply as “sludge”) is a mixture of the solid and fluid residues
(e.g., heavy hydrocarbons, formation solids, chemical precipitate) that collect in equipment and other
vessels along the production stream. Sludge is typically found as a loose material and may also be
referred to as sediment, bottoms or settlings. One study reported that the highest rate of sludge
accumulation occurs in storage tanks (API, 1989), which may result from longer residence times. Yet,
even there, accumulation can be a gradual process. Deposition rates have been reported between 1 and
4 cm/yr per well (U.S. EPA, 1993; Zielinski and Budahn 2007). Depending on the dimensions of an
individual pit or tank, disposal of the accumulated sludge might not occur until years after the start of
production.
5.5.1. Bulk Content
The composition of sludge is partly dependent on the characteristics of the produced water, though
silica and barium compounds are often the primary minerals present (U.S. EPA, 2000a). Samples
collected around the coast of Louisiana had an average solids composition of 50% SiO2 and 20% BaSO4
(Fisher and Hammond, 1994). Samples collected from Brazil had an average solid composition of 35%
SiO2 and 12% BaO (Godoy and Petinatti da Cruz, 2003).16 Both studies also reported more minor
contributions from aluminum, calcium and iron oxides. The barite in sludge is similar to that found in
scale, but there are currently no practical means to separate this mineral from the remaining sludge
due to the small size and brittleness of the precipitate (Fisher and Hammond, 1994; U.S. DOE, 2004).
Therefore, the barite is considered to be a fundamental component of the sludge, rather than a mixture
of separate wastes.
Inorganic Elements
EPA identified seven studies that measured inorganic elements in sludge. EPA separated the available
data into two sets for comparison based on the analytical methods used in the studies. This is because
of substantial differences identified between samples of drilling solids that had been analyzed with acid
digestion methods and non-destructive methods. Four studies used digestion methods on samples from
at least four states (API, 1987; U.S. EPA, 1987, 2000; Zielinski and Budhan, 2007). Three studies used
non-destructive methods on samples collected primarily from one state, with additional samples from
two others (Fisher and Hammond, 1994; Landsberger et al, 2012; Zhang et al., 2015). The majority of
these data were drawn from vertical wells. The limited data available for horizontal wells fell within
the range reported for vertical wells and so EPA combined the data from both types of wells for this
comparison. Table 5-17 presents the 50th and 90th percentile of the available data for inorganic
elements in sludge detected in at least half of one of the datasets.

16) If all of the measured BaO is present as BaSO4 then this would account for closer to 18% of the total mass, similar to samples
collected from around the Gulf of Mexico.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-36

Table 5-17. Inorganic Elements in Sludge (mg/kg)
Constituent Acid Digestion Non-Destructive
n 50th 90th n 50th 90th
Antimony 0 / 0 -- -- 15 / 17 27 54
Aluminum 9 / 9 1,500 16,221 2 / 2 46,500 50,100
Arsenic 6 / 7 3.3 4.3 17 / 17 64 436
Boron 8 / 8 34 143 0 / 0 -- --
Barium 9 / 9 1,340 8,735 21 / 21 101,000 231,000
Chromium 59 / 59 18 27 0 / 0 -- --
Cobalt 3 / 5 2.8 19 17 / 17 35 77
Copper 60 / 60 18 43 17 / 17 292 720
Iron 9 / 9 5,700 37,807 2 / 2 59,250 66,650
Lead 5 / 6 69 151 17 / 17 872 7,620
Manganese 9 / 9 72 578 0 / 0 -- --
Molybdenum 2 / 5 0.25 9.9 10 / 17 5.0 51
Nickel 49 / 59 16 30 17 / 17 32 127
Selenium 1 / 7 1.0 2.4 13 / 17 10 42
Strontium 11 / 11 200 256 18 / 18 3,425 29,570
Vanadium 12 / 12 8.9 26 0 / 0 -- --
Zinc 67 / 67 59 159 19 / 19 1,170 11,560
n = Number of Samples Detected / Total

Total concentrations are higher than acid-extractable concentrations for all constituents, regardless of
where the samples were collected. Differences of an order of magnitude or more are too large to only
be explained by regional variability. The more likely cause is that non-destructive analytical methods
measure the full constituent mass within the sample matrix, while digestion methods measure the
constituent mass that can be liberated from the matrix with a combination of heat and acid (Gaudino
et al., 2007). If a fraction of the sludge is recalcitrant, it will not dissolve during acid digestion. This can
result in an underestimation of the total concentration present in the waste. If the recalcitrant fraction
will not be released from the sludge, it may not be appropriate to consider this additional mass in
exposure estimates. However, studies have shown that reducing conditions can mobilize constituent
mass from otherwise recalcitrant minerals, such as barite (Phillips et al. 2001; U.S. DOE, 2004).
Therefore, it may still be appropriate to consider the total mass if the sludge is managed in a
biologically-active, reducing environment. This is a major source of uncertainty in the current data.
Organic Compounds
EPA identified two studies that measured organic compounds in sludge (API, 1987; U.S. EPA, 1987).
Samples were collected from vertical wells in at least three states. The uncertainties associated with
measurement of inorganic elements are not anticipated to be as great a concern for organic compounds.
Residual oil is typically present as a separate layer from other precipitate and so the mineral phase is
less likely to interfere with laboratory analysis or to limit potential exposures. Therefore, given the
relatively small number of samples available, EPA combined all available data into a single distribution.
Table 4-18 presents the 50th and 90th percentile of the available data for organic compounds in sludge.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-37

Table 5-18. Organic Compounds in Sludge (mg/kg)
Constituent
Percentile
n 50th 90th
Benzene 7 / 8 63 218
Toluene 8 / 8 15 609
Ethylbenzene 9 / 10 21 307
Xylene 2 / 2 317 571
n = Number of Samples Detected / Total

All of the data were collected around 1987, so there is some uncertainty whether these data reflect the
sludge that is currently generated. In the absence of more recent sludge data, EPA considered data for
produced water because it is one primary source of the organic compounds in sludge. Samples collected
in the last decade have a similar range of benzene, toluene, ethylbenzene and xylene (BTEX)
concentrations as those from the 1980’s. This indicates that current sludge has a similar potential to
retain dissolved and emulsified organics from produced water. In addition, the equipment used to
separate oil and water still relies on differences between the density of oil and water. This indicates
that current sludge also has a similar potential to retain heavier hydrocarbons that settle out of the
water. Based on these considerations, EPA concludes that available data can still provide useful
information about the magnitude of potential concentrations. These data show that substantial
enrichment of organic compounds in sludge is possible. However, the small number of total samples
make it difficult to draw conclusions about the overall distribution of concentrations and how
frequently higher concentrations will occur.
Radioisotopes
EPA identified thirteen studies that measured radioisotopes in sludge. The majority of these studies
collected samples from vertical wells in eight states (MIDNR/MDPH, 1991; PADEP, 1992; CADHS/DC,
1996; Pardue and Guo, 1998; NYDEC, 1999; U.S. DOE, 1999a,b; U.S. EPA, 2000a; Zielinski and Budahn,
2007; Landsberger et al., 2012). Two studies collected samples from vertical wells in two states (U.S.
DOE, 2014; Zhang et al., 2015). Radium is the most commonly measured radionuclide in sludge because
it is the most highly concentrated in produced water and frequently co-precipitates with barium. As a
result, this isotope is likely to be sequestered in the recalcitrant fraction of the sludge. However, the
uncertainties associated with measurement of inorganic elements are not anticipated to be as great a
concern for radioisotopes. Gamma radiation can easily pass through solid materials and so the mineral
phase is less likely to interfere with laboratory analysis or to limit potential exposures. A number of
radioisotopes may also be present in sludge from different sources, but the most data were available for
radium because of the potential for high activities through barite precipitation. Given the variable
amount of data available for each state and the substantial differences among the reported activities,
EPA separated the data out by state. Table 5-19 presents the 50th and 90th percentile of the available
data for radium in sludge.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-38

Table 5-19. Radioisotopes in Sludge (pCi/g)
State Well Type Radium 226 Radium 228
n 50th 90th n 50th 90th
California Vertical 5 / 5 2.3 10 5 / 5 3.7 11
Louisiana Vertical 24 / 24 667 101,244 10 / 10 560 37,392
Michigan Vertical 3 / 3 436 4,654 3 / 3 220 1,470
New York Vertical 9 / 9 2.0 6.7 8 / 9 2.1 4.3
North Dakota Horizontal 57 / 57 25 98 57 / 57 11 25
Oklahoma Vertical 9 / 9 53 1,072 7 / 9 4.6 28
Pennsylvania Vertical 25 / 25 0.7 1.1 25 / 25 0.7 1.5
Horizontal 2 / 2 281 408 0 / 0 -- --
Texas Vertical 29 / 29 124 760 29 / 29 44 187
n = Number of Samples Detected / Total

Measured scale activity is variable among the states. Yet most studies report instances of 226Ra activities
far greater than the upper bound of 4.2 pCi/g 226Ra measured in surface soil (U.S. DOE, 1981a). Thus,
there is clear potential for elevated activities in this waste. However, it is not possible to define a
representative distribution of potential activities with available data because of the approach used to
select sample locations. Some studies conducted initial surveys of the pits and tanks with hand-held
instruments to guide sample collection toward areas of elevated activity, which may overestimate the
prevalence of higher activities. For example, some samples from Louisiana reported by Fisher and
Hammond (1994) have activities nearly two orders of magnitude higher than those measured in other
states. Such high activities are theoretically possible and have been reported in pipe scale, but are
unlikely to be as common as data from this study might suggest. Other studies may underestimate
potential activities due to the small number of samples reported. For example, samples from California
reported by CADHS/DC (1996) have lower activities than most other states. However, the same study
identified much higher activities in both produced water and scale, which makes it likely that higher
activities can also occur in sludge.
5.5.2. Leachate
The leachate data reported in the literature analyzed by TCLP (SW846 Method 1311). This single-point
leaching test is intended to mimic acidic conditions that result from the decomposition of organic
matter in a landfill. This scenario can result in high leachate concentrations both because the solubility
of many constituents is highest at acidic pH and because strong acids can decompose mineral complexes
that would otherwise hold the constituent mass in place (U.S. EPA, 2014c). As a result, these data have
the potential to overestimate releases if wastes are managed under less extreme conditions. However,
because this leachate test uses a fixed amount of buffer, wastes with high alkalinity may shift the final
pH of the leachate closer to neutral. None of the available studies reported the final pH of the leachate.
This is a major source of uncertainty for the available data because the solubility of some constituents
can change dramatically over a small pH range. Thus, while available data provide useful information
about the potential magnitude of releases, it is difficult to draw conclusions about potential releases.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-39

Inorganic Elements
EPA identified four studies that measured inorganic elements in the leachate from sludge. These studies
reported samples collected from at least five states, though the amount of data from each state is variable
(API, 1987; U.S. EPA, 1987; 2000a; LADNR, 1999). LADNR (1999) and U.S. EPA (2000a) reported a
considerable amount more data for one constituent (barium) than other studies collected from
Louisiana and Pennsylvania, respectively. EPA did not identify information that could be used to
further weight the data to obtain a more representative national distribution, such as the volume of
waste generated in each state. Therefore, the data from each study was weighted equally. Table 5-20
presents the 50th and 90th percentile of the available data for inorganic elements in leachate from
sludge detected in at least half of samples.
Table 5-20. Inorganic Elements in TCLP Leachate from Sludge (mg/L)
Constituent Vertical Well
n 50th 90th
Aluminum 7 / 8 0.40 6.1
Barium 320 / 376 1.4 7.7
Boron 10 / 11 1.1 3.6
Cobalt 3 / 4 0.02 0.04
Iron 11 / 11 25 120
Manganese 11 / 11 1.9 4.1
Nickel 4 / 6 0.05 0.47
Strontium 5 / 5 6.5 7.7
Vanadium 3 / 5 0.003 0.04
n – Detection Frequency

The elements detected with the greatest frequency tend to be those that are highly soluble (e.g., boron)
or known to be deposited from produced water (e.g., barium, strontium). Most of these elements are
the same as those commonly detected in the leachate from drilling solids. Although the remaining
elements are non-detect in the majority of samples, this does not provide any indication that
concentrations are low because many samples have high detection limits. Removal of these non-detect
values would only bias the overall distribution higher. This results in uncertainty and makes it difficult
to draw further conclusions about the overall distributions.
Organic Compounds
EPA identified four studies that measured inorganic elements in the leachate from sludge. These studies
reported samples collected from at least five states, though the amount of data from each state is variable
(API, 1987; U.S. EPA, 1987; 2000a; LADNR, 1999). LADNR (1999) and U.S. EPA (2000a) reported a
considerable amount more data than other studies collected from Louisiana and Pennsylvania,
respectively. EPA did not identify information that could be used to further weight the data to obtain
a more representative national distribution, such as the volume of waste generated in each state.
Therefore, the data from each study was weighted equally. Table 5-21 presents the 50th and 90th
percentile of the available data for organic compounds in leachate from sludge detected in at least half
of samples.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-40

Table 5-21. Organic Compounds in TCLP Leachate from Sludge (mg/L)
Constituent1 Vertical Wells
N 50th 90th
Benzene 254 / 390 0.18 14
Toluene 32 / 56 0.01 5.0
Xylene 39 / 51 0.04 1.8
n = Number of Samples Detected / Total

These data show substantial enrichment of organic compounds in sludge leachate is possible. This is
reasonable given the elevated concentrations in the bulk sludge. However, because available samples
are drawn primarily from two states, it is difficult to draw conclusions about the overall distribution of
concentrations and how frequently higher concentrations will occur.
Radioisotopes
EPA identified several studies that measured radioisotopes in the leachate from sludge. However, most
of the studies only discussed results graphically or qualitatively, preventing a reliable comparison of
the data (Pardue and Guo, 1998; Phillips et al., 2001; U.S. DOE, 2004). One study reported data on 226Ra
leached from the sludge of two pits in Pennsylvania that stored produced water from horizontal wells
(Zhang et al., 2015). This study reported leachate activities ranging between 98 and 378 pCi/L. One pit
was sampled twice, with collection times set three years apart. The leachate from the two sampled
sludges decreased somewhat from 378 to 268 pCi/L over three years, while the bulk activity of the
sludge increased from 8.8 to 872 pCi/g. Over the same time, the barium content of the sludge increased
substantially. This indicates that a majority of radium accumulated in the sludge is sequestered in barite.
Zhang et al. (2015) suggests that the leachable radium is associated with carbonate minerals that form
from reactions with atmospheric carbon dioxide. DOE (2004) reached a similar conclusion, noting that
a greater fraction of radium was solubilized with nitric acid (HNO3) from sludge than pure barite scale.
5.5.3. Air Emissions
Volatile organics and radon are the constituents most likely to be released from sludge into the
surrounding air. EPA did not identify any studies that analyzed for volatile organics, but did identify
one study that measured radon emanation. This study collected samples from Oklahoma (U.S. DOE,
1999b). Table 5-22 presents the 50th and 90th percentile of the available data for radon emanation
from sludge. As previously discussed for scale, values are commonly expressed as an emanation factor,
which represent the unitless fraction of the radon released that is able to migrate out of the material
and into the surrounding air. Emanation factors may be used together with the activity of radium
present to estimate an overall emission rate.
Table 5-22. Radon Emanation from Sludge
Isotope
Emanation Fraction
n 50th 90th
Rn-222 8 / 8 0.110 0.181
n = Number of Samples Detected / Total

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-41

The limited number and geographic isolation of available samples may skew the overall distribution,
though the direction and magnitude of any bias is unknown. The measurements from sludge all fall
within the range reported for pipe scale, but are most similar to samples of disturbed scale. This is
expected because the physical properties of sludge more closely resemble disturbed scale. Individual
particles of barite and other minerals found in sludge are generally smaller and more brittle than intact
scale that plates out on the surfaces of well tubing and other equipment (Rood et al., 1998). The higher
ratio of surface area to volume of sludge provides more direct contact with the surrounding air, which
increases the rate at which radon can escape.
5.5.4. Summary – Production Sludge
Available data show that production sludge can be generated wherever oil and gas operations occur.
The primary source of constituent mass in the sludge appears to be deposition from produced water
and other fluids that are handled along the production stream. Barite, similar to that found in pipe
scale, can be a major component of the sludge. However, other settled solids such as returned fracturing
sand, formation solids, and heavier hydrocarbons can also contribute mass. However, the composition
of sludge can be highly variable and the lack of characterization data make it difficult to further refine
distribution of constituent levels in this waste.
One source of uncertainty associated with the available data are the age of the samples. Zhang et al.
(2015) found that radium activity in sludge sampled from a pit increased by two orders of magnitude
over the span of three years. Much of the accumulation is attributed to chemical precipitation, as the
activity of the produced water did not increase during this interval. This is important because the
accumulation of sludge is a gradual process. Thus, grab samples collected at random points during the
operational life of a pit or tank could significantly underestimate typical constituent levels in the sludge
at the time of disposal.
Another source of uncertainty with the available data are the spatial variability of sludge within the
pits and tanks. Solids suspended in produced water can settle out quickly once the velocity of the flow
slows at an outfall to a pit or tank. This can result in hotspots of the constituents that concentrate in
these solids. Some studies have reported higher levels of both total organic carbon and radium near the
point of discharge into pits (Freeman and Deuel, 1984; Pardue and Guo, 1998). Concentrations can also
vary based on which piece of equipment is sampled. Heavier solids and organics may settle out in
equipment early in the production stream, while chemical precipitation may dominate deposition in
pits and tanks used for water storage. Thus, grab samples from a single point in the production stream
could underestimate or overestimate the overall constituent levels in the sludge sent for disposal.
Contaminated Soil and Sediment
Spills and other releases of wastes from exploration and production activities can result in the
contamination of various environmental media (e.g., soil, surface water). EPA focused this discussion
on soil and sediment because the constituents that precipitate out or adsorb to these media are the most
likely to remain in place over time, which allows a more direct comparison of different samples. If
undisturbed, contamination may remain in place for years. Constituents in ground and surface water

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-42

are more mobile and have greater tendency to mix within the media. This makes it difficult to aggregate
these data without additional information (e.g., the time elapsed since the release, the flow rate of the
water body). Therefore, further discussion of ground and surface water was limited to identification of
damage cases based on site-specific information in Section 8 (Damage Cases).
5.6.1. Bulk Content
In total, EPA identified twelve studies that provided data from nine states. The majority of these studies
analyzed for radioisotopes. A few also analyzed for other inorganic elements, but none reported data
for organic compounds. Barium is the one inorganic element measured with any frequency in these
studies. Therefore, EPA chose to present the data for barium and radium together for comparison and
discussion. Table 5-23 presents the 50th and 90th percentile of the available data for barium and radium
in contaminated soil and sediment.
Table 5-23. Barium and Radium in Contaminated Media
State Barium (mg/kg) Radium 226 (pCi/g) Radium 228 (pCi/g)
n 50th 90th n 50th 90th n 50th 90th
California -- -- 16 / 16 0.80 30.4 19 / 19 0.92 29
Illinois 14 / 14 1,320 66,400 24 / 24 8.4 403 21 / 24 3.2 48
Kentucky 17 / 17 3,820 131,242 92 / 92 12 904 79 / 86 2.9 63
Michigan -- -- 20 / 20 153 1,626 11 / 18 2.1 206
New York -- -- 16 / 16 1.1 4.2 16 / 16 1.4 2.9
North Dakota -- -- 23 / 23 0.76 5.4 22 / 22 0.77 8.3
Oklahoma 8 / 8 4,920 416,000 61 / 61 11 406 49 / 60 0.9 15.5
Texas 1 / 1 185,400 34 / 34 14 254 40 / 40 2.0 30
Wyoming 1 / 1 1,600 18 / 18 7.4 42.4 13 / 15 3.2 5.1
n = Number of Samples Detected / Total

The bulk content of contaminated soil has the potential to be one of the most variable wastes generated.
This is because it is dependent not only on the initial composition of the waste, but also on the
magnitude of the spill and the characteristics of the soil. Many studies collected grab samples around
areas of known or suspected contamination based on visible cues (e.g., salt scar, stunted plant growth)
or hand-held survey equipment (e.g., spectrometer). As a result, it is not known whether these samples
are representative of the overall contamination at each site. Spills are rarely uniform and individual
grab samples may capture isolated “hotspots” or miss the impacted area entirely. More comprehensive
sample collection would be needed to define the full magnitude and extent of contamination. Yet the
available data demonstrate the potential for high radioactivity in contaminated soil and sediment. Maps
provided by some studies show that the extent of contamination extends several hundred square meters
across multiple locations at each site (U.S. DOI, 1997b; Zielinksi et al., 2000).
Many of the available samples represent releases of sludge and scale, but some are attributed to releases
of produced fluids based on the presence of nearby salt scars or waste management pits. To understand
whether these different types of spills result in different types of contamination, EPA compared the
available barium and radium concentrations in 25 samples. Several studies had reported the presence
of barite in the soil and sediment samples (U.S. DOI, 1997a,b; Rajaretnam and Spitz, 1999; Zielinksi et
al., 2000). This mineral is known to be present in sludge and scale, but might also precipitate

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-43

independently from liquid waste. Alternately, the dissolved radium might adsorb directly to the soil
independent of barium. The result of this comparison is shown in Figure 5-9. Sediment data were not
included because the available studies used acid digestion to analyze samples, which can significantly
underestimate total concentrations of barium in scale.

Figure 5-9: Relationship Between Barium and Radium in Contaminated Soil
This graph indicates that co-precipitation with barium is the dominant mechanism for the initial
deposition of radium. It also indicates that radium and barium tend to precipitate at a predictable ratio.
Previous studies have reported a fixed relationship between losses of barium and radium from solution
(Gordon and Rowley, 1957; Zhang et al., 2014). If this relationship reflects a standard rate of radium
incorporation, similar relationships would be expected in other precipitated waste (e.g., sludge, scale).
Therefore, EPA added an additional 34 samples of other wastes drawn from eight studies to the same
graph. The result of this comparison is shown in Figure 5-10. Only one study diverged significantly
from the relationship identified for contaminated soil (Fisher and Hammond, 1994). Therefore, data
are presented without (left) and with (right) the data from this study for comparison and discussion.

Figure 5-10: Relationship Between Barium and Radium in Different Deposited Wastes

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-44

About half the data reported by Fisher and Hammond (1994) agree well with those from other studies.
The other half tend to have higher activities than predicted by the other studies, though a similar trend
is present with increasing barium. The authors recognized this difference and noted that samples where
the barite had deposited as a thin film on the surface of other solids typically had higher activities than
those where scale precipitated independently. The authors speculated that higher levels were a result
of faster and less-selective precipitation. Fast precipitation can result from changes in temperature and
pressure as produced water is transported to the ground surface. This could mean that sludge deposited
early in the production stream may have a higher ratio of radium to barium. This would align with the
previous finding that the tanks closest to the wellhead tend to have higher total radium activity (U.S.
EPA, 1993).
5.6.2. Leachate
EPA identified three studies that analyzed leachate from contaminated soil or sediment. The activities
measured in these studies are variable and reflect different wastes that had been mixed with different
media. In addition, each study used a different leaching test to estimate potential releases. As a result,
the available data are not directly comparable and each study is discussed separately:
 Wilson and Scott (1992) collected three soil samples from around a former pipe cleaning operation
in Louisiana. Soil samples had an average activity of 1,485 pCi/g 226Ra. Leachate samples were
collected in accordance with EPA Method 1310B (Extraction Procedure Toxicity Test). The study
reported leachate activities as the activity in the total volume of fluid, which converted to 3.5 and
5.6 pCi/L. The third sample was non-detect and the detection limit was not reported.
 Pardue and Guo (1998) collected one sample of surface sediment from a water body in Louisiana
located downgradient from a pit that held produced water. The sample had an activity of 581 pCi/g
226Ra. The sample was incubated for two months after adjusting the redox conditions to +600 mV
(surficial aerobic sediment) and -250 mV (buried reducing sediment), though it was not specified
how this adjustment was achieved. The resulting pore water was separated through centrifuge and
measured. The study reported pore water activities per gram of sediment, which converted to 49
and 85 pCi/L 226Ra, respectively.
 Rajaretnam and Spitz (1999) collected soil samples from an abandoned drilling site located on a
Kentucky farm. The tank batteries on this site contained brine, sludge and other wastes. Two soil
samples had an average activity of 880 pCi/g 226Ra. Leachate tests were conducted based on ASTM
D5284-93 (sequential batch extraction) with modified extraction fluids containing HCl, NaCl, or
Na2S intended to mimic acid rain, high-salinity produced water, or anaerobic conditions. The
study reported releases around 1% of the total mass in the soil samples regardless of the extraction
fluid used, which converted to approximately 570 pCi/L. Dissolved activity was similar for both
extraction cycles.
Several studies have reported that bacteria have the ability to reduce barite and liberate barium and
radium. Some of the same studies also reported a stoichiometric imbalance between the amount of
sulfate and barium released into solution following incubation with these bacteria. This imbalance was

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-45

attributed to either re-precipitation of barium as barium carbonate (witherite; BaCO3) or sorption onto
the soil (Phillips et al., 2001; U.S. DOE, 2004). This cycle of dissolution and precipitation in response
to changing redox conditions mirrors what is known about barium chemistry during shale formation.
It is possible that radium will follow a similar cycle and either re-precipitate with barium or sorb to the
soil, which would limit transport away from the point of release. Therefore, the composition of the soil
could impact the degree to which radium is retained (IAEA, 2014). Landa and Reid (1982) found that
the clay fraction of sediment that had received produced water discharge contained 50% of the radium
mass, even though it comprised only 19% of the sediment. Any constituent mass that is adsorbed onto
the soil or bound in carbonate complexes is likely to be mobilized more readily than from the original
scale.
5.6.3. Air Emissions
Volatile organics and radon are the constituents most likely to be released from contaminated soil and
sediment into the surrounding air. EPA did not identify any studies that analyzed for volatile organics,
but identified one study that analyzed for radon. As discussed previously, values are commonly
expressed as an emanation factor, which represent the fraction of the radon released that is able to
migrate out of the material and into the surrounding air. Emanation factors can be used together with
the activity of radium present to estimate an overall emission rate. EPA identified a single study that
analyzed samples collected from Illinois, Kentucky, Michigan, Oklahoma and Wyoming (U.S. DOE,
1999b). Because the emanation fraction is not a function of activity, EPA combined data from the
different states into a single distribution. The ranges reported for each state are similar, which provides
additional confidence that these data are representative of potential releases. Table 5-24 presents the
50th and 90th percentile of the available data for radon emanation from contaminated soil and
sediment.
Table 5-24. Radon Emanation from Contaminated Media
Isotope
Emanation Fraction
N 50th 90th
Rn-222 65 / 65 0.139 0.243
n = Number of Samples Detected / Total

Emanation fractions measured from contaminated soil all fall within the range reported for disturbed
scale. This is expected because many of the samples are mixed with disturbed scale or sludge. Samples
with contaminants adsorbed to the surface are expected to release radon at comparable rates because
the radium is contained primarily on the surface of the material, which provides more direct contact
with the surrounding air. Previous studies of emanation fractions from natural soil reported a similar
range of emanation rates (IAEA, 2013). However, releases from soil and sediment may differ in the
environment because saturation with water can inhibit releases of radon and other gases.
5.6.4. Summary – Contaminated Soil and Sediment
Each of the wastes discussed in this document (i.e., spent drilling fluid, drilling cuttings or solids,
produced water, sludge, scale) have the potential to introduce contaminants into the environment.
Reports from Colorado, New Mexico, Oklahoma and Pennsylvania indicate that the most common

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-46

releases reported to these states are from produced water and drilling fluid (Kuwayama et al., 2017).
Few reports were found for releases of sludge, scale and other solids. However, a number of samples
reported in the literature are attributed to these wastes. Samples collected in Illinois, Kentucky,
Michigan, Oklahoma and Wyoming all identified elevated levels of radium activity in soil attributable
to historical contamination. It was estimated that, at the time of sampling, contamination had been
present at several of these sites for 30 years or more. The available data show that there are similar
concentrations in wastes generated today and so similar potential for contamination exists.
The comparison of barium and radium in contaminated soil indicates there is a consistent relationship
between the two precipitated elements. The presence of a predictable ratio indicates that the activity
in sludge and scale will be proportional to the amount of barite present in these wastes. With further
investigation, it might be possible to use the relationship between barium and radium to attribute
historical contamination of unknown origin to spills of exploration and production wastes. Spills are
most likely to occur near where the waste is produced (e.g., wellhead) or stored (e.g., reserve pit, tank
battery) as a result of equipment failure or human error. As a result, proximity to equipment can be a
useful criterion to locate historical spills along with other visual cues (e.g., salt scars). However, samples
collected near the point of release will be biased toward contaminants that precipitate out of solution
and remain insoluble. Some of the constituent mass may remain in solution because of the high ionic
strength of produced fluids and be transported some distance downgradient before settling out. It will
be considerably more difficult to locate and attribute this dispersed contamination.
Conclusions
Both hydraulic fracturing and directional drilling have the potential to impact the composition of E&P
wastes. This review shows that there can be orders-of-magnitude variability in the composition of each
waste type, though trends are apparent for certain constituents that might be used to predict where
elevated constituent levels are more likely to occur. Some inorganic elements (e.g., lithium,
molybdenum), organic compounds (e.g., benzene) and radioisotopes (e.g., radium) appear to be
correlated with either the organic carbon content of the source rock or the salinity of the formation
water. Horizontal wells are frequently drilled a greater distance through high-organic rocks with saline
formation water and so higher constituent levels may be more common in the wastes from these wells,
but similar orders-of-magnitude levels may also occur in the wastes from vertical wells. Therefore, it
is likely that similar regulatory controls would be appropriate for the wastes from both types of wells.
This review focused on publicly-available sources of data. There appears to be a substantial amount of
additional data that is not in the public domain. Some studies make reference to databases, which EPA
was not able to locate (Dingman and Angino, 1968; Rittenhouse et al., 1968; Collins 1969; U.S. DOE,
1991; Hitchon et al., 2000; U.S. DOE, 2004). Other studies provide summary statistics or qualitative
discussion, but not the underlying data. It is often unclear how much data are contained in each
database or study. However, the majority of these sources address produced water, which is already the
waste with the greatest amount of data available. Therefore, further efforts to assemble existing data
are unlikely to substantially improve the characterization of constituent levels (i.e., concentration and
activity) present in and released from other wastes.

Management of Exploration, Development and Production Wastes
Section 5: Waste Characterization 5-47

The majority of available data reflect wastes as generated. However, wastes may then be intermingled
with other wastes during storage or treated in preparation for disposal. Limited information is available
about the impact that these management practices have on the composition and behavior of the wastes.
Available data indicate that certain practices can increase the bulk concentration of some constituents,
though the exact cause is not always clear. As a result, an evaluation of potential environmental impacts
based on the wastes as generated could underestimate releases to the environment. Further sample
collection and analysis would be needed to characterize potential releases to the environment during
storage and subsequent disposal of E&P wastes.
There are limited data available on the magnitude of releases through leaching or volatilization for any
waste type. The data that are available reflect an assortment of analytical methods that capture different
environmental conditions and cannot be reliably aggregated into a single dataset. Although more data
are available on the bulk concentrations in these wastes, that alone is not a reliable indicator of how
much mass can be released into the environment, particularly for wastes with recalcitrant mass. Further
sample collection and analysis would be needed to fully characterize potential releases to the
environment during storage and subsequent disposal of E&P wastes.
Despite the various sources of uncertainty, the available data provide an estimate of constituent levels
that can be used to determine which constituents are most likely to concentrate in each waste. Taken
together with relationships identified among different waste types and different constituents, the data
can also estimate where elevated concentrations are more likely to occur. High-organic-content rocks
and high-salinity water are well correlated with elevated levels of inorganic and organic constituents
and are defining features of hydrocarbon-bearing formations. As a result, elevated constituent levels
are unlikely to be geographically isolated.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-1

6. State Programs
States have the primary authority over the disposal of non-hazardous waste within their boundaries.
Therefore, it is critical to understand how the different state programs are implemented for E&P wastes.
The scope and specificity of state programs is variable. State programs vary, both among states and
different regions of a state, to account for regional factors (e.g., formation type, meteorology) that
impact the types of waste generated and the appropriate methods to manage those wastes. EPA has
previously reviewed state programs, both as part of the 1987 Report to Congress and a more recent
effort in 2014 (See Section 2: Summary of Agency Actions). However, state programs have continued
to evolve to address emerging issues from hydraulic fracturing and other technological advances.
Therefore, EPA conducted an updated review to better understand how state regulations currently
address E&P waste management and to highlight inconsistencies, lack of specificity, or possible gaps in
coverage.
Methodology
EPA evaluated the state regulations for 28 of the 34 oil and gas producing states, which represent more
than 99% of the annual U.S oil and gas production by volume, according to U.S. Energy Information
Agency data (U.S. DOE, 2018c,d).17 The six states with the lowest overall production were not included
in this review (i.e., Alabama, Arizona, Maryland, Nebraska, Oregon, South Dakota). For each state, the
latest version of E&P regulations were obtained electronically from the source identified on the state
oil and gas agency website at the time of the review (February through December 2018). In some cases,
such as California and Pennsylvania, the statute or enacting legislation was also obtained because it
provided additional clarifying information on the waste requirements. Solid waste and radiation
protection regulations were obtained in a similar manner. In addition, readily obtainable guidance and
policy documents related to E&P waste were obtained from state agency websites. The review of
guidance and other policy documents is unlikely to be as comprehensive as the review of applicable
regulations because the Agency cannot guarantee that every potentially relevant document was
identified. This review did not evaluate regional or field-specific requirements promulgated by state oil
and gas boards. These special rules, often called “Orders” or “Special Field Rules,” may contain
additional more stringent requirements for managing wastes and are unlikely to be less stringent than
state regulations. Likewise, some counties, notably in Colorado and California, may place additional
controls on oil and gas operators that are more stringent than state regulations.
Disposal of RCRA-exempt wastes in Class II injection wells is allowed by permit in most states, and the
associated regulatory program may fall under either the oil and gas agency or the environmental

17) This review of regulations did not include tribal regulations applicable in Indian country, because EPA was unable to conduct a
similar review of tribal programs as many do not have the solid waste regulations compiled in a readily searchable online format.
Generally, state laws do not apply in Indian country. The amount of tribal land varies across the United States but a majority is
concentrated in EPA Regions 8, 9 and 10. EPA is fully aware that oil and gas exploration, development, and production operations
take place in these areas, and so will continue to look at regulatory and program management responsibilities in tribal lands
specific to managing wastes from these activities.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-2

agency. Several states specifically exempt underground injection control (UIC) disposal facilities,
including the pits and tanks associated with these facilities, from the E&P regulations because they are
covered under UIC facility rules. While UIC pits and tanks do not fall under E&P regulations in these
states, EPA considers them waste management units. However, a comprehensive evaluation of state
UIC regulations was outside the scope of this review.
The first step in the review was development of an inventory of potentially applicable state regulations.
Oil and gas, solid waste, and radiation protection regulations for each state were reviewed and the
regulatory language related to 61 specific technical elements organized into 12 general topic areas were
captured verbatim and documented in a spreadsheet (Appendix C: State Programs). This spreadsheet
reflects the initial capture of regulations potentially applicable to the review. The inventory also
included capturing the potentially applicable definitions associated with the regulations, dates of the
regulation or subsequent updates (where available) and a link to the original document.
Uncertainties
EPA used the information compiled in the detailed spreadsheet to review state regulatory programs.
These programs were found to vary not only in scope and specificity, but also in the language used to
define different wastes and the relevant controls. This variability resulted in uncertainties when
defining the regulatory coverage of some states. The following text provides an overview of how the
Agency considered and addressed the major sources of uncertainty identified during the review to
ensure that it was as complete and consistent as possible.
Specificity: The specificity of state regulations differ for a range of topics, such as signage; groundwater
monitoring; financial security; setbacks and location restrictions; run-on/runoff controls; inspections;
spill notifications and corrective action. These regulations may specify controls for the individual well,
the associated waste management units (e.g., pits, landfills), or site-wide. For record-keeping purposes,
any of these requirements were considered evidence that regulatory controls are in place. Many states
also include general statements that E&P operations shall not cause pollution to the land, water or air
and shall not adversely affect environmental resources. These statements were sometimes part of the
definition of “waste” or were stand-alone requirements in various parts of the regulations. States may
have great flexibility in interpretation of such requirements, but EPA considered these general
requirements to be too broad to address the specific protections for floodplains, endangered species,
surface water and groundwater found in 40 CFR 257.3. Therefore, states that only include general
protection requirements were listed as not having coverage with respect to 40 CFR 257.3.
Not Allowed versus Not Addressed: EPA did not identify regulations or guidance from certain states
for some practices, such as land application, beneficial use, offsite landfills or commercial facilities. In
these cases, it was not clear based on the regulatory text whether the practice is prohibited in the state
or unaddressed because it is not known to occur in that state. State agencies may have internal policy
or case history that provide further guidance for these subjects. However, such documents are difficult
to obtain and so these regulations are considered ambiguous. For these situations this review generally
considered the practice to not be allowed (for counting purposes), but noted that it could be allowed

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-3

and controlled on a case-specific basis. In some cases, the practice was mentioned in other parts of the
regulation but with unspecified controls, and so the practice was assumed to be allowed.
Specific Requirements versus Supervisor/Agency Approval: Each state had a different approach to the
content and level of direction in regulations for E&P wastes. Common approaches included:
 Prescriptive set of rules and regulations with specific technical requirements across many areas
that must be followed to receive permit approval or comply with permit by rule (common for high
production states)
 General or performance-based requirements that operators must incorporate into planning
documents and application submittals that are reviewed and approved by the agency
 Agency defined requirements on a site-specific basis (common for low production states)
Where states provided performance-based requirements, such as “pit and tank bottoms must be
impermeable” or “tank construction shall be compatible with waste and not leak,” the review
considered there to be controls in place for record-keeping purposes.
Deviations Allowed: Many states allow deviations to rules or specifications “with approval of the
supervisor or director.” Allowance for modification beyond the written regulations can provide state
programs with flexibility to address the rapidly changing technology in E&P production and the
variability of site-specific conditions. For example, many pit liner regulations specify a material type
or minimum thickness but allow the operator to propose an alternative, to be approved by the director.
Because there is a specific requirement in place, this review considered the element to be incorporated
in the state program and that the deviation did not alter protectiveness specified by the regulation.
Level of Detail: States develop and revise regulations based on the conditions, practices and experiences
within the state so it is not surprising that not all states address all topics with the same level of detail.
However, it presents a challenge in comparing the comprehensiveness of regulation across states
because EPA cannot be as familiar with which specific operations occur in each state. For example, pit
definitions and the associated regulations in some states may address only a few types of pits and do
not address certain other types. In other states, there are separate detailed requirements for each pit
type. In this review for each pit element (e.g., permits, liners, fencing, netting, groundwater
monitoring, leak detection), the presence of any topical regulation, regardless of the type of pit, was
considered evidence that regulatory controls are in place. For example, if a state defines five types of
pits and provides liner requirements for only one, this review concluded that the state did provide
regulation on pit liners. Where possible, the state overviews identified the limitations of coverage or
missing details.
Definitions and Terms: The review identified several challenges with the definitions and terms used in
the regulations. A common challenge was the use of ambiguous or undefined terms. For example, many
states require waste to be disposed at an “authorized facility” but do not provide a definition or further
details on the specific types of facilities that might be authorized to accept the waste. Other terms such
as “significant,” or “appropriate,” or phrases such as “earthen pit,” and “above the water table” were

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-4

ambiguous and the level of protectiveness could not be identified but were still considered to provide
regulatory control. As discussed above, definitions for pits are variable among states. Some states define
pits by function (e.g., collection pit, reserve pit, emergency pit), and other states define pits by length
of service (e.g., temporary pit, permanent pit) or content (e.g., freshwater pits, high chloride pits). Many
states use a combination of classifications. Other reviews of E&P regulations note the same issue of
inconsistent nomenclature for pits. STRONGER recognized this issue and provided guidance for
consistent nomenclature in their 2017 Guidelines (STRONGER, 2017).
Definitions for a specific term can vary among states. Across the states several terms are used to describe
the non-salable liquids generated by producing oil and gas wells: brine, salt water, produced water and
produced fluids. The discussions in this summary use the terminology defined by the state when
discussing specific examples. The term “brine” is used when a specific state regulation is not being
referenced. The review noted many other examples of multiple terms for the same concept. Conversely
the review identified some terms that were defined differently by different states. The term waste, as
defined in most state regulations, has a dual meaning. In addition to the traditional definition
(byproduct or unusable material), it refers to the inefficient production of oil and/or gas such that the
resource is lost or not recoverable. Unless otherwise specified, the traditional meaning is implied here.
Definitions were used to support the evaluation of the level of detail and the coverage of state
regulations. States with many definitions that included technical terms and subdivision of waste unit
type (i.e. multiple pits or tank types) were deemed to be more comprehensive because they addressed
a wider range of potential risks.
Complexity of Regulations: E&P regulations cover many different technical areas and processes and
are necessarily complex. Some state regulations were organized and presented in a centralized and
comprehensive manner making it clear what was required and what was prohibited. For example,
Oklahoma provided a list of E&P wastes, and a corresponding list of the acceptable disposal methods
for each of the wastes. Some state regulations were complex and difficult to navigate because several
different agencies had jurisdiction over different parts of the regulations. For example, The California
Department of Conservation, Division of Oil, Gas and Geothermal Resources regulates oil and natural
gas production in the state. The California Environmental Protection Agency has several departments,
such as the Department of Toxic Substances Control, the State Water Resources Control Board and the
nine Regional Water Quality Control Boards, and California Integrated Waste Management Board, all
of which may be involved in the permitting process for oil and gas operations.
Analysis of Specific Elements Across States
EPA organized the review of state programs into 12 topic areas, which are further divided into 61 sub-
elements. These elements were selected based on a review of elements incorporated for similar waste
management units. For each state, an initial binary (yes/no) determination of whether regulations were
in place for each of the 61 elements was assigned using the approach described above, supplemented
by a second focused review of the regulatory text. The following discussion provides a summary of state
programs organized around some of these topic areas. More comprehensive summaries for all topics on

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-5

a state-by-state basis and the spreadsheet used to document the regulatory text that formed the basis
for this review are provided in Appendix C (State Programs). Specific examples provided in this
summary are generally intended to demonstrate the range of requirements among different states and
should not be interpreted to be representative of states not listed.
6.3.1. Waste Management Location Requirements (Siting and Setbacks)
All states in this review except Missouri and Florida provide some form of location and siting
requirements to address where oil and gas operations and associated waste management activities can
be located. Siting requirements can be found in either the oil and gas rules or the solid waste rules
depending on the nature of the waste operation (onsite versus offsite; temporary use versus permanent
disposal). This review included review of state regulations only. Some counties and municipalities may
have specific rules for oil and gas setbacks. Siting regulations can be found as broad general overarching
requirements, or more commonly as dispersed rules associated with the construction or operation of
specific waste units such as pits or tanks. Requirements commonly include setback distances from
human and environmental resources including residences, schools, inhabited structures, roads,
wetlands, floodplains, groundwater and wildlife habitats. At least five states (e.g., Alaska, Nevada, New
Mexico, North Dakota, Utah) also consider seismicity and land stability conditions in siting for landfills
or salt water treatment facilities that accept E&P wastes. Alaska also includes permafrost and ground
thawing as site conditions to be considered in siting and design of drilling waste monofills. Texas, which
accounts for the largest contribution to oil and gas production and number of wells drilled per year,
does not have state-wide setback rules for E&P waste, and allows communities to set siting
requirements.
Applicability: Most rules focus on the siting of pits and tanks located onsite (within the well pad area)
and only a few states discuss siting requirements for offsite commercial and centralized facilities for
treating, recycling or reclaiming E&P wastes. Texas and Oklahoma have extensive sections in their
regulations addressing siting criteria for offsite commercial and centralized facilities. North Dakota
provides siting, construction and operation requirements for salt water handling facilities, which may
be located onsite or offsite. Some states do not have siting requirements for drilling, completion and
production pits or brine holding tanks because they are considered part of the drilling site/pad and
proposed locations are included in the drilling permit application (APD) that is approved by the state.
The APD form may include information on pit construction and location. Some states, including
Colorado and Michigan have requirements for both the general well facility, and waste unit (pits)
setbacks from environmental features such as groundwater or floodplains.
Location and Siting Requirements: A direct comparison if location and siting requirements in different
states is challenging because the coverage of waste operations varies among the states. Some states
regulate siting based on the type of waste managed. Pits containing completion fluids and flowback
water may have more stringent setback requirements than reserve pits and others only address specific
situations (e.g., emergency pits). For example, the setback requirement from a continuously flowing
watercourse in New Mexico ranges from 100 ft (temporary pits with low chloride fluids) to 300 ft
(permanent pits and temporary pits with higher chloride fluids). Arkansas has residential and

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Section 6: State Programs 6-6

environmental receptor setbacks for crude oil tank batteries and gas well produced fluids storage tanks
but minimum groundwater depth is not specified for all mud, circulation or reserve pits. Several states
(e.g., Colorado, Louisiana; Haynesville shale areas only, Ohio) provide different setbacks for urban and
non-urbanized areas, as defined by the state. Three states (i.e., Florida, Missouri, Montana) do not
provide residential, environmental or depth to groundwater setback distances for E&P wastes and allow
the operator to propose locations and provide the distance to lease lines, water resources, buildings and
water supplies to be approved by the agency. Michigan requires an environmental assessment of the
site including identification of more than a dozen special hazards and conditions within 1,320 feet of
the surface facility as part of the well permit process.
Most states have a general rule that prohibits the siting of a well or waste management unit (specifically
pits, tanks or landfarms) in a location that could allow pollution or damage to environmental resources.
Solid waste requirements for siting landfills that accept E&P wastes may have more stringent
requirements. All states with location or siting requirements have rules for siting wells or waste
operations near floodplains or surface water resources, however, the definitions of the resources differ.
For example, New Mexico and Pennsylvania provide a list of specific types of water bodies and
environments for setbacks but many other states only reference setback from the 100-year floodplain.
In Arkansas, a closed loop system is required for oil-based drilling fluid pits, mud pits or circulation
pits within 100 feet of a pond, lake, stream, extraordinary resource waters, ecologically sensitive water
bodies, or natural and scenic waterways. Of the 28 states in the review, only Colorado addressed siting
related to endangered species in E&P regulations. Nine states included endangered species in landfill
requirements applicable to E&P wastes. Tank battery siting is often included as part of the general well
permit, but Arkansas and Idaho have specific setback rules for crude oil and brine tanks. Table 6-1
provides a summary of state requirements for location restrictions and setback distance.
Table 6-1. Summary of Required Setback Distances in Select States.
Resource
Number of States
with Specific
Setback Distances
Setback Requirement
(Lower Bound)
Setback Requirement
(Upper Bound)
Residences/Inhabited
Structures 17 100 ft (OH) 1,000 ft (CO, NM)
1 mile (UT)
Floodplains/Surface
Water Resources 24 50 ft (OH) 1,500 ft from groundwater
intake (IL)
Groundwater 12 20 in below seasonal high
groundwater table (9 states)
50 ft below the base of waste
(UT)

Siting and location of landfills permitted for disposal of E&P waste are generally regulated by the state
solid waste agency. As noted before, the states classify exempt E&P wastes in a variety of ways (solid
waste, non-hazardous waste, special waste, and industrial waste), each with different rules for landfill
siting and location. Because of the long-term nature of disposal in landfills, solid waste landfill siting
rules generally provide more stringent requirements and specificity in guidance for siting and location
than oil and gas rules. For example, Class 1 solid waste landfills in Nevada may not be sited where

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groundwater is less than 100 feet below ground surface, which is more than twice the distance of the
most stringent E&P waste rule identified in this study. Similarly, states with rules for commercial
operations for recycling or reclaiming oil, or disposal of brine tend to provide detailed siting
requirements. Texas, for example, does not allow commercial recycling facilities in the 100-year flood
plain, in a streambed, or in a sensitive area (as defined in regulations), and has a setback distance of 150
feet from surface water and supply wells. When reviewing applications for siting a commercial
recycling facility, Texas considers waste type and volume, distance to residences and receptors such as
wetlands, surface water, coastal resources, groundwater, and water supplies.
6.3.2. Tank Requirements (Onsite/On-Lease)
Tank requirements may apply to one or more types of tanks (e.g., drilling fluid, produced water, oil).
In some states, regulations for E&P waste tanks are incorporated in the above ground storage tank
regulations. Regulations typically address the tank construction materials, secondary containment, and
fluid/waste management practices. For this review, it was assumed that tanks holding crude oil can
accumulate waste solids and so are considered potential waste management units.
Tank Berms and Containment Specifications: Approximately 74% of states reviewed (18 of 28) have
some requirements for tank berms or secondary containment. Some states require secondary
containment for all tanks, while others have certain criteria. For example, in North Dakota, dikes for
produced water tanks and berms at salt water handling facilities are required when deemed necessary
by the director. In Colorado, secondary containment is required for “all tanks containing oil,
condensate, or produced water with greater than 3,500 milligrams per liter (mg/L) TDS (not including
water tanks with a capacity of less than 50 barrels) and must be constructed of steel rings or another
engineered technology.” Nevada regulations state that “dikes or fire walls are required around
permanent tanks for the storage of oil located within the corporate limits of any city or town, where
tanks for storage are less than 500 feet from any highway or inhabited dwelling, less than 1,000 feet
from any school or church or are so located as to be deemed by the Division to be a hazard.”
Half of the states with berm requirements (9) provide a specific capacity for the secondary containment
with most of them being 1½ times (or 150%) the size of the tank. Florida specifies two times the tank
capacity, and New York regulations state that secondary containment must be able “to contain 110
percent of the volume of either the largest tank within the containment system or the total volume of
all interconnected tanks, whichever is greater.” While the size and dimensions are not specified for any
state, Utah regulations indicate “berms of sufficient height and width to contain the quantity” and
Colorado regulations indicate the secondary containment “shall be sufficient to contain the contents of
the largest single tank and sufficient freeboard to contain precipitation.” Regulations for five states
(i.e., Colorado, Florida, Mississippi, North Dakota, West Virginia) indicate secondary containment
must be impermeable or sufficiently impervious, while Idaho is the only state that provides a specific
permeability value (1×10-9 cm/sec). In Colorado, operators are also subject to tank and containment
requirements under Rules 603 and 604 (safety regulations for location and siting facilities and wells).
Two states (Pennsylvania and Wyoming) refer to requirements under 40 CFR Part 112 (Spill

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Section 6: State Programs 6-8

Prevention Control and Countermeasure Plans). Several states address construction and design
requirements for piping that penetrates the dike, and the maintenance of the berm and bermed area.
Tank Construction Material Requirements: Some requirements for tank construction are provided in
regulations for 11 of 28 states reviewed. These states include general requirements indicating that tanks
must be impermeable (i.e., Pennsylvania), constructed with compatible materials (i.e., Illinois, New
Mexico, New York, North Dakota), and properly designed/constructed to contain liquids or minimize
pollution (i.e., Colorado, Oklahoma, Virginia). Alaska regulations refer to API standards for tank
construction, and Ohio regulations indicate that only steel tanks are allowed for burial. Colorado
requires a synthetic liner under the entire bermed tank area and compliance with National Fire
Protection Association (NFPA) Code 30 for tank construction.
Netting for Open Tanks: Six states require netting for open tanks to protect birds and other wildlife
from contacting possible hazardous fluids in open tanks and other open storage vessels (i.e., Arkansas,
Illinois, Indiana, Montana, New Mexico, Texas). Oklahoma requires protection for migratory birds but
does not make specific mention of netting.
Modular Large Volume Tanks (MLVTs): These temporary tanks are constructed from modular
components and used to hold large volumes of water for drilling, completion and production. The
figures below are examples of MLVTs used for oil and gas operations. MLVTs are only addressed in
regulations for two states. In Pennsylvania, modular aboveground storage structures that exceed 20,000
gallons require prior approval. Siting approval is required for site-specific installation of these modular
structures at each well site. North Dakota regulations “allow portable-collapsible receptacles used solely
for storage of fluids used in completion and well servicing operations, although no flowback fluids may
be allowed.” MLVTs must utilize a sealed inner bladder and conform to API construction and
installation standards. Tanks must have signage on all sides clearly identifying the fluid within.
Tank Monitoring Requirements: Tank monitoring was found to be required in only a few state
regulations. In Florida, “all tanks shall be installed, maintained, pressure tested, and protected against
corrosion in accordance with generally accepted petroleum industry standards and practices.”
Additionally, “tanks containing sour fluids shall be equipped so they can be gauged, sampled and the
temperature measured at ground level.” Alaska regulations for crude oil tanks require an external
method of leak detection and inspections after a significant seismic event, however it is unclear if these
regulations apply to E&P waste fluids stored in tanks. Virginia and New York both require tank
inspections. Several states require high level alarm and automatic shutoff systems on tank batteries to
prevent overflows. Tank inspection requirements are quite variable. Many states do not specify
inspections but require tanks to be maintained fluid tight or without leakage. Other states allow self-
inspections (including visual observations of bermed areas and sumps) or require prescribed inspections
annually (Virginia) or up to every 10 years (Alaska).
Tank Solids Removal: Tank operation and management may include removal of solids (and any
intermingled fluids) that accumulate in the bottom of crude oil and salt water tanks. Four states require
permits for tank bottom removal (i.e., Kentucky, North Dakota, Pennsylvania, Texas). Although other

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states may not require permits for tank bottom removal, some do provide procedures for managing tank
bottom wastes. In Illinois, a permit is not required but approval may be needed for some non-regulated
disposal options. Oklahoma requires permits for commercial tank bottom reclamation facilities. In
Colorado, tank bottom removal does not require a permit, but the disposal facility must be permitted.
Wyoming regulations indicate “dispose of produced water, tank bottoms, and other miscellaneous solid
waste in a manner which is in compliance with the Commission's rules and other state, federal, or local
regulations.” Regulations for managing tank bottoms are often included in disposal requirements such
as beneficial use, land application, and commercial reclamation/recycling. In Kentucky, recycling of
tank bottoms is encouraged as a best management practice.
6.3.3. Pit Construction and Operation Requirements
Pits may be used at any stage of E&P operations (e.g., drilling, completion, workover, production). A
wide range of both fluids and solids can be stored in pits. All 28 states in this review regulated the
construction or operation of pits in some manner. However, one state, Missouri, does not provide
technical requirements for pits for any of the topic areas discussed below. Most states have developed
regulations based on some type of classification, generally based on the intended use for the pit and/or
the type of materials held in the pit. These classifications reflect the anticipated level of risk from use
of pits over time. For example, pits used to hold produced water have a higher potential for risk than
those that hold fresh water and so may have more stringent design requirements. Additionally, some
states classify pits based on their expected time of use (temporary or permanent). Production pits
holding brine over long periods of time are generally considered to represent a higher risk of release
than pits used during the much shorter drilling process.
Pit Types: The number of types of pits defined in the regulations varies considerably among the states
reviewed. At one extreme, Texas regulations describe more than 15 different types of pits using both
pit names or pit function. At the other, New York and Pennsylvania only identifies a single category
of “brine pits” in the regulations. The different approaches used to define pits makes comparison and
analysis of regulations difficult. Because most state E&P regulations are organized by process
(e.g., permitting, drilling, production), pit regulations are often dispersed throughout the rules. Many
states regulate pits based on the general stage of the process (e.g., drilling, production, disposal). Within
these categories there are often further subdivisions that reflect the specific use (e.g., reserve pit,
circulating pit, skimming pit, flare pit) or pit contents (e.g., fresh water, drilling fluids, produced water).
Some pit types, including emergency pits, burn pits, gas processing plant blowdown pits and centralized
or multi-well pits do not fit directly under these categories and are often addressed separately. EPA
also identified structures in some state regulations referred to as “impoundments.” In West Virginia, an
“impoundment” only refers to earthen structures for fresh water. In Alaska, New Mexico and Ohio, an
“impoundment” may be lined and hold waste materials. In some states, impoundments greater than a
certain size are regulated and permitted as dams.
Many states have revised pit and drilling regulations since 2011 and specifically address existing pits
that do not conform with the updated regulations. Generally, non-conforming pits must be closed
within 3 to 12 months, brought into conformance, or receive approval for continued use by the state

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Section 6: State Programs 6-10

agency. A few states have addressed historical pits (“inactive pits”) that may not have been constructed,
operated or closed in accordance with current rules, and either provide regulations for inventory of
such pits (e.g., Indiana) or a program to address remediation of these pits. The assessment and
remediation programs are generally under the direction of the state environmental agency.
Commercial Pits and Centralized Pits: Some states with significant oil and gas production, such as
Texas, Oklahoma, Wyoming and New Mexico, have separate regulations that cover commercial E&P
waste management facilities. In 6 of the 28 states reviewed, centralized pits used to support multiple
wells are regulated separately from individual well site pits primarily because of their large volume and
unique design considerations (i.e., Colorado, Pennsylvania, New Mexico, Oklahoma, West Virginia,
Wyoming). Centralized pits associated with disposal wells are not consistently addressed in the pit rules
in all states. Although Class II disposal wells are regulated under the Safe Drinking Water Act’s UIC
program, the aboveground pits and other waste management units are not. Oklahoma includes detailed
specifications for surface facilities (pits) associated with commercial injection wells, but most other
states do not specifically address the subject or make a distinction between salt water holding pits and
pits associated with permitted disposal wells.
Prohibited Pits: Almost half the states reviewed (13 of 28) identified specific types of pits that are
prohibited; however, no state prohibits pits entirely. Many states include a general prohibition on pits
that would cause pollution or release to the environment. The most common prohibitions on specific
types of pits are those that contain a specific type of waste (e.g., oil, brine, salt cuttings), that are unlined
(sometimes called “earthen”), are permanent (i.e., present longer than a specified duration), and
unpermitted. Other specific prohibitions include those constructed on fill material, those associated
with particular well types, that are in areas that are hydraulically linked to groundwater or surface
water, and that are within a certain distance of specific zones, such as residential areas.
Permits: Permits are required for pits in 16 of the 28 states reviewed; however, in some states permits
are only required for certain types of pits. For example, only commercial brine pits in Texas and pits
holding greater than 5,000 barrels of fluid in Virginia require permits. In many of the states where a
specific pit permit is not required, the pit is permitted as part of the APD or covered as permit by rule.
In New York and Alaska, permits are not required but a management plan for drilling fluids (including
pit information) is required as part of the well APD permitting process.
Freeboard: Most of the states reviewed (20 of 28) include some requirement for maintaining adequate
freeboard. Sixteen of the 20 states include specific requirements, which typically range from 1 to 3 feet.
Some states have different freeboard requirements based on various pit types. For instance, Kansas
provides different values: drilling, work-over, burn and containment pits have a minimum freeboard
of 12 inches, while emergency and settling pits have a minimum freeboard of 30 inches. Some states
also only provide values for particular pit types. Utah, for example, specifies a 2-feet of freeboard for
evaporation ponds only. Four other states (i.e., Indiana, Ohio, Texas, Wyoming) do not provide specific
values for freeboard but rather indicate “adequate” or “sufficient” size/capacity of the pit is necessary.
Table 6-2 provides a summary of state-specific requirements freeboard.

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Table 6-2. Summary of Freeboard Requirements for Pits.
Freeboard States
1 ft 3 – KS (drilling, workover, burn and containment pits), KY, MS (brine pits)
2 ft 11 – AK, AR, CO, ID, LA, MS, OK, PA, TN, VA, WV (centralized pits)
2.5 ft 1 – KS (emergency and settling pits)
3 ft 2 – MT, NM
75% capacity 1 – FL

Signage: Most states (19) require signage for the site, though seven (i.e., Colorado, Indiana, Mississippi,
New Mexico, North Dakota, Oklahoma, West Virginia) require signage for pits specifically. Five of
these states specify signs for particular pit types. For example, offsite reserve pits and commercial
disposal pits in Oklahoma, temporary salt water storage pits in Mississippi, and freshwater in both pits
and portable-collapsible receptacles in North Dakota all require specific signs. New Mexico regulations
specify that “the operator shall post an upright sign not less than 12 inches by 24 inches with lettering
not less than 2 inches in height in a conspicuous place on the fence surrounding the pit or below-grade
tank, unless the pit or below-grade tank is located on a site where there is an existing well…that is
operated by the same operator.”
Fencing and Netting: Eighteen states have fencing requirements for pits. Some states require fencing
only for certain pit types. For example, North Dakota requires fencing for open pits and ponds that
contain salt water or oil, while fencing is not required for drilling or reserve pits used solely for drilling,
completing, recompleting or plugging, except beyond 90 days of operation. Ten states do not have
fencing requirements for pits with Mississippi regulations specifically stating that fencing is not allowed
to ensure agency field personnel have access to facilities for inspection and regulatory enforcement
purposes, that first-responders (fire, sheriffs, emergency medical personnel, etc.) have ready access in
the event of emergencies (fires, explosions, etc.), and that site personnel have a ready means of egress
or escape from such facilities in the event of emergencies.
Ten of the 18 states that require fencing also require netting. North Dakota regulations state that all
pits and ponds that contain oil must be fenced, screened and netted. Colorado regulations state that
“where necessary to protect public health, safety and welfare or to prevent significant adverse
environmental impacts resulting from access to a pit by wildlife, migratory birds, domestic animals, or
members of the general public, operators shall install appropriate netting or fencing.” Idaho does not
specify fencing or netting directly but rather “site-specific methods for excluding people, terrestrial
animals and avian wildlife from the pits.” There are no states that require netting without fencing.
Table 6-3 provides a summary of the specific state requirements for fencing and netting. Idaho was
counted as both fencing and netting for accounting purposes.
Table 6-3. Summary of Required Fencing and Netting for Pits.
Requirement Number States
Fencing Only 8 IL, MI, LA, OH, OK, PA, VA, WV
Fencing and Netting 10 CO, ID, IL, IN, MT, ND, NM, TX, UT, WY

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Liners: Twenty-seven of the 28 states require liners for at least some types of pits. Most states (22 of 28)
clearly state that liners are required by providing specifications, such as pit types, liner types and liner
requirements. Other states, like Nevada, are more indirect and imply that a liner is required by
prohibiting unlined pits. Michigan prohibits earthen pits for well completion fluids, produced fluids
and tank bottoms but does not define earthen pits so it is unclear if lined pits are included in the
prohibition.
Some states provide specifications for liners, including thickness and material. Liner thickness typically
ranges from 10 to 60 mils, and materials are often synthetic or materials with equivalent performance,
such as compacted clay, as approved in each state. Colorado regulations are substantial and specify
different pit types/waste characteristics and associated liner requirements. Idaho regulations indicate
that all liners should have a minimum permeability of 1×10-9 cm/sec, and thicknesses of 20 mils for
reserve, well treatment and other short-term pits and 60 mils for long-term pits. In contrast, New York
regulations state that a “watertight material” is required for brine pits. In Tennessee, liner seams should
be 4 inches wide and welded. Seams are not allowed in Michigan.
State requirements for liners may vary by pit type. Some states have different requirements for liners
based on the material being contained, while others require liners for some liquids but not others.
Arkansas regulations, for example, require synthetic or compacted clay liners for reserve pits, synthetic
or bentonite liners for drilling mud, and concrete liners for mud and circulation pits. In Illinois, fresh
water reserve pits do not require liners but other pits do. Mississippi only requires temporary salt water
pits be lined with an approved impervious material. Michigan specifies secondary containment (i.e.
liners) for flare pits.
Leak Detection and Monitoring: Ten of the 28 states require leak detection and monitoring, though
specifications provided in the regulations varies. For example, leak detection/monitoring is only
required for long-term pits (more than one year) in Idaho, for brine pits in Texas, and centralized pits
in West Virginia. The type of detection/monitoring also varies by state. For instance, Indiana requires
visual inspections while Colorado requires the use of pit level indicators within designated setback
locations. Two additional states (i.e., Utah, Wyoming) may require leak detection/monitoring in
sensitive areas, as required by the agency or specified in a permit.
Berm Requirements: Seventeen states include requirements for berms with varying degrees of detail.
Four have requirements for the site, but not pits specifically (i.e., Florida, Ohio, Virginia, West
Virginia). Six states (i.e., Alaska, Indiana, Mississippi, New Mexico, Oklahoma, Texas) have general
requirements for pits indicating, for example, that “pits shall be protected from surface waters by dikes
and drainage ditches” (Mississippi) or that berms should be “adequately sized” to prevent pit inundation
(Indiana). Alaska states that “if practical, confinement diking in construction of a reserve pit must be
avoided. If confinement dikes are necessary, they must be kept to a minimum.” Five states (i.e., Idaho,
Kentucky, North Dakota, Pennsylvania, Tennessee) provide specific berm requirements for pits. For
example, berms in Tennessee should have a 2:1 slope and a width of 2 feet. Idaho regulations state that
the top of bermed pit walls be a minimum of 2-feet wide and “pits that have constructed berms ten or

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Section 6: State Programs 6-13

more feet in height or hold fifty acre-feet or more of fluid must also comply with the dam safety
requirements.”
Depth to Groundwater: A minimum depth to groundwater for pit siting is required by 12 of the 28
states reviewed. Seven states provide specific depths that range from 20 inches in Pennsylvania and
West Virginia to 25 feet in Oklahoma. Table 6-4 provides a summary of the specific state requirements
for depth to groundwater.
Table 6-4. Summary of Required Depth to Groundwater for Pits.
Minimum Depth to
Groundwater States
1.7 ft PA, WV (centralized pits only)
4 ft MI
5 ft KS, LA
10 ft AR
20 ft WY
25 ft OK

Three remaining states provide more tailored requirements. Tennessee regulations state that, “in areas
where groundwater is close enough to the surface that it will be encountered in construction of a pit,
pits shall be constructed above ground, or the operator shall use a closed-loop system.” Utah uses a
ranking approach to evaluate potential impacts based on pit location. Surface to groundwater depth is
one criterion considered in this evaluation, and if less than 25 feet, a closed-loop system should be
considered instead of constructing a pit. In New Mexico, temporary pits containing low-chloride fluid
may not be located where groundwater is less than 25 feet below the bottom of the pit.
Groundwater Monitoring: Over half of the states reviewed (15 of the 28) address groundwater
monitoring either on a site-wide basis or specific to an E&P waste management unit (e.g., pit, landfill).
Eight of the 15 states address groundwater monitoring on a site-wide basis (i.e., Colorado, Illinois,
Michigan, Nevada, Ohio, Tennessee, Utah, Virginia), rather than for any specific type of E&P waste
management unit. In Wyoming, however, baseline groundwater monitoring is conducted for the entire
drilling site and may be also required for an E&P waste pit if it is located in a sensitive area. The
remaining seven states (i.e., California, Louisiana, North Dakota, Oklahoma, Pennsylvania, Texas, West
Virginia) require some type of groundwater monitoring for specific E&P waste management units. For
example, Texas requires groundwater monitoring for commercial recycle/reclaim pits, brine pits and
other types of pits if required by a permit. Oklahoma requires groundwater monitoring for flowback
pits with capacities greater than 50,000 barrels and brine disposal well pits. Pennsylvania requires
groundwater monitoring for centralized impoundments and unconventional well construction. North
Dakota states that monitoring is required, which may include groundwater monitoring, for all buried
or partially buried structures at treatment plant facilities.
Inspections: Eleven states include requirements for the inspection of pits. The different approaches
used to define pits makes it difficult to further summarize the requirements. The regulations often
specify the type of pit requiring inspection, which varies considerably among the states:

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 Illinois and Indiana require inspection of concrete storage structures, which are allowed to be used
as pits for production and waste materials.
 Louisiana requires inspection of reserve pits.
 Mississippi does not require inspection of pits, but the state must be given the opportunity to
inspect the pit prior to use.
 New Mexico requires that the state be given the opportunity to inspect pits prior to use. The
following inspection activities are required:
o A minimum of daily inspections for temporary pit containing drilling fluids while the drilling
or workover rig is on location, then weekly so long as liquids remain in the pit.
o Weekly inspections of permanent and multi-well fluid management pits with the use of an
on-site log while the pit has fluids at least monthly until the pit is closed. Inspections will
include monitoring of the leak detection system during operation and before the system is
covered.
o If netting or screening is not feasible for a permanent pit or multi-well fluid management pit,
the operator shall inspect for dead migratory birds and other wildlife on a monthly basis.
 North Dakota requires all reserve pits to be inspected prior to installation of the liner and use.
 Oklahoma requires inspections only for flowback water pits.
 Pennsylvania requires inspections at least once a year for onsite brine or residual waste disposal.
 Texas requires inspections of all brine pits and commercial recycle/reclaim pits, as well as others
as specified by permit.
 Tennessee requires pre-permit inspections for all “pollution control structures.”
 West Virginia requires inspections of pits and impoundments with a capacity greater than 5,000
barrels (at conventional wells) and all centralized pits/impoundments prior to placement of any
fluid, every two weeks for the life of the pit, and within 24 hours of significant rainfall (2 inches
or more within a 6-hour period). For other types of pits, the state must be notified and given the
opportunity to inspect prior to use.
 Wyoming requires periodic inspections of pits by the operator (weekly at a minimum) with
documentation of such inspections sent to the Supervisor (state) at their request.
6.3.4. Pit Closure Requirements
Regulations were reviewed for several pit closure requirements including removal of waste material
prior to closure, timing for pit closure, inspection and sampling. A total of 22 of the 28 states directly
address pit closure requirements. One of those states (Kentucky) includes the requirements in an
Operator’s Manual instead of regulations. Tennessee regulations do not specifically address pit closure
but require removal of fluids from pits “as soon as practical after fluids have accumulated in them.”
Table 6-5 provides a summary of the general types of pit closure requirements identified in this review.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-15

Table 6-5. Summary of Pit Closure Requirements.
Criteria Number of
States
Specific
States
Liquids Removal 23 AR, CA, CO, FL, ID, IL, IN, KS, KY, MI, MS, MT, ND, NM, OH, OK, PA, TN,
TX, UT, VA, WV, WY
Solids Removal 17 AR, CA, CO, FL, ID, IL, IN, KS, KY, MT, ND, NM, OH, PA, TN, TX, UT, WY
Closure Timeframe 22 AR, CA, CO, ID, IN, KS, KY, MI, MS, MT, ND, NM, NV, NY, OH, OK, PA,
TN, TX, VA, WV, WY
Inspections 10 CO, ID, LA, MS, ND, OK, PA, TX, UT, WV

Removal of Liquids and Solids: Most states (23 of 28) require removal of liquids prior to pit closure.
Some states specify the types of pits that require liquid removal. For example, drilling, reserve and
temporary pits in North Dakota and hydraulic fracturing fluid pits in Ohio must have liquids removed
prior to filling and compaction. Details about the method of liquid removal or disposal are provided in
some regulations and may include disposal at an appropriate facility, offsite reuse or downhole disposal
(i.e. injected liquids and semisolids, or placement of cuttings in the annular space of a plugged well).
Illinois regulations specifically state that “all oilfield brine and produced waters shall be removed and
disposed of in a Class II UIC well.” In Colorado, Oklahoma, Utah and Wyoming, natural evaporation is
an accepted method of removal.
Six of the states that require removal of liquids do not require removal of solids prior to pit closure
(i.e., Michigan, Mississippi, Oklahoma, Pennsylvania, Virginia, West Virginia). Michigan regulations
state that drilling mud pits with waste in place shall be stiffened (i.e., earthen materials are mixed with
the pit contents to provide physical stability and support for the pit cover) prior to encapsulation.
Sixteen of the 28 states reviewed require removal of solids in some instances prior to pit closure.
Arkansas, Texas and Wyoming specify the types of waste that either require removal or may remain in
the pit. North Dakota regulations specify that contents of any earthen pit/receptacle be removed and
disposed, while waste in drilling and reserve pits be encapsulated in the pit and covered. Idaho requires
all pits to remove and dispose of solids and the pit liners.
Regulations in four states (i.e., Alaska, Missouri, Nevada, New York) do not mention removal of liquids
or solids prior to pit closure. However, Alaska regulations include a general requirement that “upon
completion the operator shall proceed with diligence to leave the reserve pit in a condition that does
not constitute a hazard to freshwater.”
Closure Schedule: A total of 22 of the 28 states provide a schedule for pit closure. Some include specific
requirements while others are more general. Timeframes typically range from 30 days to 12 months
after the completion of particular site operations. For example, in North Dakota, pits should be
reclaimed according to the following schedule: earthen (unlined) pits within 30 days after operations
have ceased, reserve pits within 30 days after the drilling of a well or expiration of a drilling permit,
and reserve pits within a reasonable time but not more than one year after the completion of a shallow
well. Nevada regulations indicate pit closure be conducted “as soon as weather and ground conditions
permit, upon final abandonment and completion of the plugging of any well.” Colorado regulations for

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reclamation are not specific for pits but indicate that reclamation for wells be completed within three
months on crop land and 12 months on non-crop land.
Inspection and Sampling: Seven states require some form of inspection and sampling prior to pit
closure (i.e., Colorado, Idaho, Louisiana, Oklahoma, Texas, Utah, West Virginia). Idaho regulations
state “the owner or operator must notify the Department at least 48 hours prior to removal of the pit
liner so an inspection may be conducted.” Idaho also requires the testing of residual fluids and any
accumulated solids in the pit to determine which disposal facility can accept the material. In Texas,
inspections are required for commercial recycling/reclamation pits, or as required by a permit for other
pit types. Texas also requires the testing of soils prior to closure. Testing parameters include pH, TPH,
BTEX, as well as numerous metals. Colorado requires an inspection for overall drill site reclamation
but not for pits specifically. Two states (i.e., Mississippi, Pennsylvania) require inspections, but no
sampling. In Mississippi, emergency pits require inspection following the emergency period. Arkansas
only requires sampling. Inspection and sampling are not required in Wyoming but may be determined
to be necessary based on site-specific conditions. Inspections are not required for North Dakota, but
approval is needed prior to pit reclamation. EPA identified no state regulations that require
groundwater monitoring or testing subsequent to pit closure, but such a requirement could be included
by the state agency in an individual well or pit permit. Several states that require sitewide baseline
groundwater monitoring also have requirements for monitoring post well construction. Virginia, for
example, requires groundwater monitoring consisting of initial baseline groundwater sampling and
testing followed by subsequent sampling and testing after setting the production casing or liner.
Pennsylvania requires that bodies of water and watercourse over and adjacent to horizontal directional
drilling activities must be monitored for any signs of directional drilling fluid discharge.
Financial Assurance: For all states reviewed, separate financial assurance is not required for pit closure.
Instead, if required, it is included in the general permit/bond for the well or overall facility.
6.3.5. Spill Notification and Corrective Action
A total of 26 of the 28 states reviewed included requirements for notification of spills in their
regulations. Many of these regulations are not specific to a waste type and can include spills of crude
oil or raw materials, neither of which is covered under the RCRA exemption. Some states refer to spills
as “releases” or “nonpermitted or unauthorized discharge.” New Mexico separately defines “major
release” and “minor release,” with different requirements for each. Some states (i.e., Idaho, Montana,
Nevada, Utah, Wyoming) discuss spills in sections with other accidents or emergencies, such as fires,
lightning strikes or blowouts. Other states (i.e., Colorado, Illinois, Indiana, Kansas) have separate “spill”
sections. Mississippi regulations only address spill notification and corrective action in offshore rules.
Notification: For the 26 states with spill notification requirements, immediate notification is required
following a spill or discharge from a waste management unit, especially for an uncontrolled
spill/discharge that enters (or threatens to enter) nearby surface water or impact groundwater.
Immediate notification is generally required to the Department/Commission/Division and a timeframe
is often specified, ranging from 30 minutes to 24 hours. Some states (e.g., Michigan) do not give a

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Section 6: State Programs 6-17

specific timeframe but instead require the incident to be reported immediately or promptly. This initial
notification is often communicated verbally, although North Dakota does have an initial online
notification system that requires the location, type of incident, cause of the incident, volume released,
volume recovered, potential environmental impacts and actions taken. A follow-up written report is
typically required within five to 15 days, depending on the state. Additional requirements for initial
spill notification can vary based on quantity of material spilled. Table 6-6 provides a summary of the
spill notification requirements for Wyoming and New Mexico.
Table 6-6. Summary of Spill Reporting Requirements in Select States.
State Spill Type/Material Quantity Timeframe/Report Type
New Mexico
Volume that may with reasonable
probability be detrimental to water
or exceed specified standards
Not specified
Verbal report: immediately, within 24 hours
Written notice: 15 days
Major release >25 barrels Verbal report: immediately, within 24 hours
Written notice: 15 days
Minor release >5 and <25 barrels Written notice: 15 days
Wyoming
Uncontained spill or authorized
release which enters, or threatens
to enter, waters of the state
Any/All
Verbal report: by next business day
Written report: 15 working days
Contained spill <1 barrel (42 gallons) Reporting not required (maintain record of
incident)
Contained spill >1 and <10 barrels Written report: 15 working days
Contained spill >10 barrels Verbal report: Next business day,
Written report: 15 working days

States have a minimum spill volume threshold at which notification is required, which range from any
amount spilled (e.g., Kansas, North Dakota, Utah) to 2,100 gallons (e.g., Nevada). Most states have a
minimum quantity between 210 and 420 gallons (i.e., five to ten barrels). Volume requirements may
also vary for the type of fluid spilled. Some states provide general descriptions (e.g., deleterious
substances18) while others are more specific, such as crude oil, brine or produced water. For example,
in both Arkansas and Illinois, immediate notification is required for a spill of one barrel of crude oil
and/or five barrels of produced water. The type of notification required can further vary based on
different waste characteristics or site conditions. For example, in Montana, immediate notification is
required for the following cases: “(a) the spill, leak, or release of more than 50 barrels of oil or water
containing more than 15,000 parts per million (ppm) TDS; (b) the spill, leak, or release of any amount
of oil or of water containing more than 15,000 ppm TDS that enters surface water or groundwater; (c)
the spill, leak, or release of any amount of produced water that degrades surface water or groundwater.”
Colorado regulations indicate that notification is required within 24 hours of the following: (1) a
spill/release of any quantity that impacts or threatens to impact any waters of the state, a residence or

18) The term “deleterious substance” has a broad range of definitions across the states using the term. For example, in Montana it
includes all CERCLA and RCRA hazardous material and waste definitions, and any petroleum product, whereas in Oklahoma and
Mississippi the term is more limited to oil and gas operations “…any chemical, salt water, oil field brine, waste oil, waste emulsified
oil, basic sediment, mud, or injurious substance produced or used in the drilling, development, production, transportation,
refining, and processing of oil, gas and/or brine mining.”

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occupied structure, livestock or public byway; (2) a spill/release of one barrel or more of E&P waste or
produced fluids is spilled or released outside the berms or secondary containment; or (3) a spill/release
of five barrels or more regardless of whether the spill/release is within the berms or other secondary
containment.
Corrective Action: Twenty of the 28 states reviewed include discussion of corrective action in the
regulations. Some states (e.g., Montana, Utah), provide general statements indicating that leaks/spills
be contained and cleaned up promptly. Some (e.g., Colorado) include specific cleanup criteria for
specified contaminants in soil and groundwater, while others (e.g., Kansas) provide details for the
corrective action approach. In Kansas, “the following cleanup techniques shall be deemed appropriate
and acceptable to the commission: physical removal, dilution, treatment, and bioremediation.”
Regulations in Illinois provide detailed approaches for crude oil spills as well as produced water spills,
while Texas regulations provide similar details specifically for soil contaminated by crude oil in non-
sensitive areas. Additionally, some states (e.g., Michigan, Virginia) include details in a spill
management or abatement plan.
Some regulations provide timeframes for performing corrective actions. For example, spills greater than
42 gallons or that pollute or threaten to pollute the waters of Pennsylvania require an initial written
report within 15 days and a site characterization report within 180 days to determine the extent of
contamination resulting from the spill and document initial response actions. In Idaho, leaks that
develop in a pit or closed-loop system require corrective action within 48 hours to include removing
all liquid above the damage or leak line.
6.3.6. Offsite Landfills
Regulations for disposal of E&P wastes in offsite landfills may be found in either the state regulations
for E&P waste, solid waste or both. To determine if wastes can be placed in offsite landfills it may be
necessary to consult both sets of regulations. Therefore, this review considered both E&P and solid
waste regulations. However, cross references are sometimes unclear or inconsistent because solid waste
regulations often do not specifically discuss E&P wastes or define the type of landfill required for
disposal.
Offsite Disposal Allowed: Twenty-five of the 28 states reviewed address offsite landfill disposal of E&P
wastes in regulations. The three remaining states (i.e., Missouri, Mississippi, Tennessee) may allow
offsite disposal, but it was not clear in the regulations reviewed. For example, Mississippi solid waste
regulations delegate exclusive authority for disposal of nonhazardous oilfield waste, both commercial
and noncommercial, to the Mississippi Oil and Gas Board, but offsite disposal methods are not addressed
in the regulations. A fact sheet regarding disposal of wastes from the BP oil spill indicates that landfills
are an acceptable disposal option if waste meet the state and federal definitions of non-hazardous
(MSDEQ, 2010).
Some state regulations do not require E&P wastes be disposed in a particular type of disposal facility
but rather state “a permitted facility.” When the type of facility is specified, municipal solid waste
landfills are the most common (e.g., Indiana, Kansas, Montana, Pennsylvania, West Virginia).

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-19

Municipal solid waste landfills are designed according to regulations from 40 CFR Part 258, which
include liners and groundwater monitoring, among other requirements, and so are generally
considered protective provided that the waste meets acceptance criteria. Other offsite disposal options
may include industrial landfills, special waste landfills, commercial facilities and recycling facilities.
For example, Alaska regulations specify drilling waste monofills as a particular type of permitted
landfill. E&P wastes in Colorado may be disposed at permitted commercial disposal facilities, while
New Mexico regulations specify recycling facilities. Oklahoma regulations state the type of facility for
disposal of E&P wastes is based on either Department of Environmental Quality approval or landfill
permit requirements. States generally classify landfills based on the risk from the wastes allowed, and
set different protective criteria (design, operation, and monitoring) for each type of landfill.
Details about allowable waste types are provided in some of the state regulations but generally do not
address every individual waste type. Ohio regulations indicate that a solid waste facility is acceptable
for “drill cuttings that have come in contact with refined oil-based substances or other sources of
contamination.” In Illinois, waste classified by the state as naturally occurring radioactive material
(NORM) with activities at background levels may be disposed at a permitted non-hazardous special
waste landfill, while NORM waste above background levels requires disposal at a waste facility
permitted by the Illinois Department of Nuclear Safety. Most regulations, however, focus on pit wastes,
with less attention to tank wastes and little mention of other exempt wastes (pipe scale, pigging wastes,
produced sand, dehydration and sweetening wastes, spent gas plant filter material, and associated
wastes). North Dakota appears to be the only state with regulations to explicitly identify filter socks
and other filter media in E&P regulations.
Waste Testing: Testing of waste prior to offsite disposal is required in seven of the 28 states reviewed
(i.e., California, Idaho, Illinois, Louisiana, New Mexico, Oklahoma, Texas). In Illinois, testing is
necessary only for wastes that might have NORM. Idaho requires routine characterization of waste
received for facilities permitted to receive E&P waste. Wyoming and Utah do not require testing for
all wastes, but it may be deemed necessary by the Supervisor/Division on a site-specific basis. Site
specific waste control plans in New York may also include a requirement for testing. Individual disposal
facility permits may require testing of wastes prior to acceptance.
Daily Cover: The use of E&P wastes as a daily cover was not specifically addressed in any of the state
regulations reviewed. A report prepared for the West Virginia Department of Environmental
Protection noted that the drill cuttings received often have too high a moisture content, which makes
it difficult to meet specifications for compaction (WVDEP, 2015). However, a report by the ANL noted
that stabilized oil and gas wastes have been used as daily cover in Louisiana. (U.S. DOE, 2006). New
Mexico and Texas indicate that stabilized, uncontaminated solids may be suitable for use as daily cover
at landfills. In New York, such waste also appears able to be used as part of the cap but cannot be within
10 ft of the final cover. In Arkansas, Nevada, Oklahoma, Texas and several other states, regulations
allow unspecified alternate materials to be used for daily cover (potentially including drill cuttings,
produced sand, petroleum-contaminated materials) if the operator shows that the alternative materials
can control wastes without presenting a threat to public health and safety and the environment.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-20

6.3.7. Land Application
Land application consists of applying waste to the land surface as a means of treatment and disposal.
More than half of the states in this review (17 of 28) address land application of E&P wastes through
regulations. Nearly all these states (15 of 17) provide specific limitations or conditions for application,
which may include waste characteristics, site conditions and operational requirements. A number of
states have regulations for land application of septic sludges and other industrial byproducts, but the
regulations were not incorporated into the current review. For these remaining states, it is unclear if
land application of E&P wastes is prohibited.
Waste Types: The types of E&P waste that may be land applied vary by state. Some states allow more
than one type of waste to be land applied. Table 6-7 provides examples of the different types of waste
allowed for land application in each state.
Table 6-7. Summary of Wastes Allowed for Land Application.
Waste Type States
Water-Based Drilling Fluids and/or Cuttings AR, CO, IN, KS, OK, PA, TX
Oily Waste Including Materials Containing Crude Oil, Condensate or Wastes that Contain
Hydrocarbons (Such as Soil, Frac Sand, Drilling Fluids, Drill Cuttings and Pit Sludge) CO, NM, OK, PA, U
Drilling Fluids, Produced Water and Produced Water-Contaminated Soils, Waste Crude
Oil, Sludges, and Oil-Contaminated Soils WY
Drilling and Production Fluids VA
Special Waste Defined as “Gas and Oil Drilling Muds, and Oil Production Brines” KY
Crude Oil Bottom Sediments IL, IN
Naturally Occuring Radioactive Material (NORM) MS, TX

Permits: There is a wide range of permit requirements for land application amongst the 17 states. Six
clearly require permits (i.e., Arkansas, Indiana, Oklahoma, Pennsylvania, Texas, Wyoming). Two
either do not require them (Colorado) or only require under certain conditions (Virginia19). Six do not
mention permits for land application in state regulations (i.e., Illinois, Kansas, Kentucky, Mississippi,
New Mexico, Utah). Of the six states that require permits, Indiana and Texas only require permits for
off-lease application of E&P wastes. In Wyoming, permits are issued by the Department of
Environmental Quality.
Waste Testing: Almost all of states that allow land application (16 of 17) include some limits or
conditions for land application of the waste, though the level of detail varies. Some states provide
numerical requirements for land application. Various examples from both Indiana and Virginia include:
TDS < 1,500 mg/L, Cl < 1,000 or 5,000 mg/L, Fe < 7 mg/L, Mn < 4 mg/L, Oil and Grease < 15 mg/L, pH:
6-9. Some states place restrictions on physical properties, such as the presence of a visible sheen or free
water. Other states (e.g., Texas) specify the limits for the soil after application, such as 226+228Ra
< 30 pCi/g or < 150 pCi/g of any other radionuclide.
Location Restrictions: Most states (14 of 17) have some application site restrictions provided in the
regulations. Some of those states only allow land application of wastes on lease property, the site of

19) According to the disposal application form, if TDS exceeds 5,000 mg/kg a permit may be required by VA DEQ.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-21

origin, or “lands previously disturbed by well site construction and drilling operations.” Colorado
allows for land application onsite or at a centralized waste management facility. Oklahoma and Texas
provide specifications for commercial soil farming facilities; some of which are different from or add
to those for non-commercial sites. For instance, in Oklahoma, commercial soil farming facilities have
setbacks for incorporated municipalities: 3 miles for populations 20,000 or less, or 5 miles if greater
than 20,000. A majority of the 14 states also provide operational conditions for land application.
Wyoming and Kentucky do not provide specifications in their regulations, while Arkansas includes
criteria in a permit. Some states provide buffer zones/setback restrictions for the application site,
including distances from surface water bodies and site boundaries, as well as conditions for the site,
such as depth to groundwater and soil types. Table 6-8 provides a summary of the location and siting
restrictions for land application of E&P wastes.
Table 6-8. Location and Siting Restrictions for Land Application.
Siting Restrictions IN KS NM OK PA TX UT VA
Lo
c
a
t
i
o
n

Re
s
t
r
i
c
t
i
o
n
s

Surface Water Body X X X X X X
Water Supply X X X X X X
Site Boundary X X X X X
Highways X
Rock Outcrops, Sinkholes X
Building X X X
Pipeline X
Drainage X X X
Si
t
e

C
o
n
d
i
t
i
o
n
s

Depth to Bedrock X X X
Depth to Groundwater X X X
Soil Type X X X
Hydraulic Conductivity X
Slope X X X X
Chloride (in Soil) X
Previous Land Application X
Chloride (in Groundwater) X
Salinity X

Examples of weather-related restrictions include prohibiting land application during precipitation
events or when ground is frozen or snow-covered. Loading rates are provided for nine states and may
include general performance criteria (will not result in runoff or pooling) or values for specific loading
rates. The maximum depth of waste applied, and the depth of tilling is specified in nine states.
Mississippi required tilling waste into the soil only if precipitation exceeds 25 inches per year. Three
states provide regulation on how the waste is to be applied to the soil including the use of injection,
pressurized diffusers, disking, or tilling methods and prohibition on gravity feeders, and use of
bulldozers and backhoes for incorporating cuttings into soil. Table 6-9 provides a summary of the
operational conditions for land application in specific states.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-22

Table 6-9. Summary of Operational Conditions Required for Land Application.
Operational Conditions/Criteria Specific States
Resulting Concentration in Soil CO, MS, TX, UT
Weather-Related Application Restrictions IN, KS, OK, PA, VA
Rates to Prevent Runoff, Ponding, Erosion CO, IN, KS, NM, PA, UT, VA
Depth of Incorporation IL, MS, PA
Maximum Application Thickness CO, KS, NM, OK, TX, UT
Enhance Bioremediation CO (oily waste), NM
Timeframe for Application CO, KS, NM, UT (Hours/Day after Received)
IN (Only Daylight Hours)
Loading Rate NM, OK, PA
Specific Method of Application (Type, Vehicle, etc.) IL, OK, UT

6.3.8. Beneficial Use
EPA defines beneficial use to be the substitution of non-hazardous industrial secondary materials,
either as generated or following additional processing, for some or all of the virgin, raw materials in a
natural or commercial product (“analogous product”) in a way that provides a functional benefit, meets
product specifications, and does not pose concerns to human health or the environment” (U.S. EPA,
2016c). State agencies have the primary authority to determine whether beneficial use of a non-
hazardous material is allowed within the state and may use definitions that differ from EPA. For
example, some states may classify the processing of waste for oil recovery to be beneficial use. A survey
of state management practices for E&P wastes in 2013 included questions about beneficial use
(ASTSWMO, 2015). A total of 11 states indicated that they had approved various beneficial uses for
drill cuttings (concrete, road base, grading), drilling fluid (concrete), sludge (road application),
produced water (dust suppressant, de-icing agent) and other wastes. There is little information available
about the frequency of different uses or the volumes of waste involved. However, states have developed
requirements for certain beneficial uses of E&P wastes.
Types of Waste: Eleven of the 28 states included in this review have requirements that address
beneficial use of E&P wastes. Seven states have requirements incorporated into regulations, three
provide guidelines (i.e., Alaska, Pennsylvania, Texas), and one outlines requirements in an agreement
between the state Division of Highways and Department of Environmental Protection (i.e., West
Virginia). The most common use is road application of E&P waste fluids to control dust, stabilize
unpaved surfaces, and de-ice road surfaces. Table 6-10 provides a summary of the uses allowed for each
type of waste in these states.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-23

Table 6-10. Summary of Waste Types Allowed for Beneficial Use.

State
Type of Waste for Beneficial Use Type of Beneficial Use
Fluid Sludge/Sediment/Solids
AK None Drill Cuttings
Construction of Roads, Pads and Berms on Oil
and Gas Properties Owned or Operated by the
Company
AR None Crude Oil Tank/Pit Solids Oiling (Lease Roads)
CO Produced Waters
(Flowback Fluids Prohibited) None Dust Control (Lease Roads)
LA Brine None Roadspreading, Deicing
MI Brine None Dust and Ice Control, Road Stabilization
NY Brine (Flowback and Marcellus
Shale Water are Prohibited) None Dust Control, Unpaved Road Stabilization,
Ice/Snow Reduction
OH Brine
(Horizontal Wells Prohibited) None Dust and Ice Control
PA Production or Treated Brine
(Not from Shale Formation) None Dust Control, Road Stabilization
TX Treated Fluid Oily Waste
Waste Solids
Treated Fluid: Any Approved Re-Use That is
Not Considered Disposal
Oily Waste: Roads (Lease or County), Firewalls
Other Waste Solids: Concrete Bulking Agents,
Landfill Cover or Capping Material, Landfill
Berms, Construction Fill Material or Treated
Aggregate, Closure or Backfill Material,
Firewall, or Other Construction Fill Material
WV Brine None Prewetting, Anti-Icing, Deicing
WY Drilling Fluids, Produced Water
Produced Water-Contaminated
Soils, Waste Crude Oil, Sludge,
Oil-Contaminated Soils
Roadspreading, Road Application

Testing Requirements: These 11 states include a wide range of requirements for waste characteristics
and operational conditions. Wyoming requires slightly different analyses for particular waste types.
Table 6-11 provides a summary of common testing requirements for beneficial uses in select states.
Additional analyses may be required by certain states. Colorado requires sampling of soil adjacent to
road application and includes a list of 18 organic compounds and three additional parameters (electrical
conductivity, sodium adsorption ratio and pH). Texas requires testing of one sample from each 200
cubic yards of treated products.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-24

Table 6-11. Summary of Beneficial Use Testing Requirements.
Parameter
WY
AK AR CO MI NY TX WV Drilling Fluid
and Cuttings
Petroleum-
Contaminated
Soil
Produced
Water and
Contaminated
Soil
TPH X X X X X
TDS X X X X X
SO4 X
H2S X
Cl X X X
Ca X X X
Na, Fe X X
Ba, Pb X X X X X X X
Ag, As, Cd, Cr, Hg, Se X X X X X
Ra-226 X
Oil/Grease X X
Benzene X X X X X X X
Toluene X X X
Ethylbenzene X X X
Xylene X X X
TOX X X X
TOX – Total Halogenated Organics

Limitations on Use: States also provide specific restrictions for the site of use, such as distance from
surface water body and grade of the roadway. Some provide more general description for the site. For
example, Colorado regulations state that roadspreading may be conducted on lease roads outside
“sensitive areas.” Six of the 10 states also provide operational conditions for beneficial use. New York
and Pennsylvania specify setbacks from surface water bodies of 50 and 150 feet, respectively. In New
York and Pennsylvania (when brine is used for dust control or road stabilization), a maximum roadway
grade of 10 percent is allowed and brine may not be applied to wet roads during rain or when rain is
imminent. Brine may not be applied between sundown and sunrise, except for ice control in Ohio and
when applied for dust control/road stabilization in New York. Michigan, Texas and Wyoming do not
include such requirements in their regulations.
Application rates for natural gas brines in West Virginia are “limited to 10 gallons per ton for pre-
wetting use, 50 gallons per lane mile for anti-icing use, and 100 gallons per lane mile for de-icing use.”
Ohio regulations state “the maximum uniform application rate of brine shall be 3,000 gallons per mile
on a 12-foot-wide road or 3 gallons per 60 square feet on unpaved lots.” Pennsylvania regulations
indicate “The road should initially be spread at a rate of up to one-half gallon per square yard (typically
after the road has been graded in the spring). The road should subsequently be spread at a rate of up to
one-third gallon per square yard no more than once per month unless–based on weather conditions,
traffic volume or brine characteristics–a greater frequency is needed to control dust and stabilize the

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-25

road. The application rate for race tracks and mining haul roads should be determined for each site and
should not exceed one gallon per square yard.” New York regulations do not provide a numerical value
but state that “the brine application must not be used at a rate greater than needed for snow and ice
control.”
Vehicle requirements are provided for three states. In Pennsylvania, “brine must be spread by use of a
spreader bar with shut-off controls in the cab of the truck…and each vehicle used to spread brine shall
have a clearly legible sign identifying the applicator on both sides of the vehicle.” Ohio regulations
specify “the discharge of brine through the spreader bar shall stop when the application stops…the
applicator vehicle shall be moving at least five miles per hour at all times while the brine is being
applied…The maximum spreader bar nozzle opening shall be three-quarters of an inch in
diameter…the angle of discharge from the applicator vehicle spreader bar shall not be greater than
sixty degrees from the perpendicular to the unpaved surface…only the last twenty-five per cent of an
applicator vehicle's contents shall be allowed to have a pressure greater than atmospheric pressure;
therefore, the first seventy-five per cent of the applicator vehicle's contents shall be discharged under
atmospheric pressure.” When brine is used for dust control or road stabilization in New York, “a
spreader bar or similar device designed to deliver a uniform application of brine must be used; the
application vehicle must have brine shut-off controls in the cab…when the application vehicle stops,
the discharge of brine must stop; and the vehicle must be moving at least five miles per hour when
brine is being applied.”
Some states provide additional details in their regulations. Arkansas, for instance, states “immediately
following completion of the application, all liquid fractions shall be immediately incorporated into the
road bed with no visible free-standing oil; and no lease road shall be oiled more than twice a year.” In
Michigan, the well owner may not use brine for beneficial use but may convey or transfer it for use by
another party. In addition, the administrative requirements for beneficial use of E&P waste vary
amongst the states reviewed. For example, Ohio requires a permit, Texas requires a permit for off-lease
only, New York requires a written petition, and Kansas requires an application. Ohio also provides
detailed information about the approval process, and the Texas permit application provides detailed
requirements for treating and recycling oil and gas solid waste for commercial or industrial use. Table
6-12 provides a summary of common restrictions on the placement of brine and other waste liquids on
roadways.
Table 6-12. Summary of Restrictions on Placement of Waste Liquids on Roadways.
Site and Operational Restrictions Specific States
Si
t
e

Re
s
t
r
i
c
t
i
o
n
s

Distances to Surface Water Bodies NY, PA
Grade NY, PA
Within 12ft of Structures Crossing Water Bodies or Crossing
Drainage Ditches NY, OH

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-26

Table 6-12. Summary of Restrictions on Placement of Waste Liquids on Roadways.
Site and Operational Restrictions Specific States
Op
e
r
a
t
i
o
n
a
l

Re
s
t
r
i
c
t
i
o
n
s

Weather-Related (Flooded, Snow Covered, Frozen Ground) NY, PA
Prevent Pooling/Runoff, Impact to Surface Water Bodies AR, CO, PA
Time of Day NY, OH (except for ice control)
Specific Loading Rate NY, OH, PA, WV
Vehicle Requirements NY, OH, PA
Avoid Vegetation NY, OH

6.3.9. NORM and TENORM
The wastes generated during drilling, completion, production, workover and closure may contain
elevated concentrations of certain radioactive elements (“radionuclides” or “radioisotopes”). EPA uses
the general term “technologically enhanced radioactive materials (TENORM)” to refer to these wastes.
EPA defines TENORM as "naturally occurring radioactive materials that have been concentrated or
exposed to the accessible environment as a result of human activities such as manufacturing, mineral
extraction, or water processing. Technologically enhanced means that the radiological, physical, and
chemical properties of the radioactive material have been altered by having been processed, or
beneficiated, or disturbed in a way that increases the potential for human and/or environmental
exposures.” State regulations use terminology that includes TENORM, NORM, and naturally occurring
and/or accelerator-produced radioactive material (NARM). There can be important distinctions
between these different terms, as some states specifically exclude wastes classified as NORM from state
radiation regulations. The current discussion uses TENORM for all wastes that have the potential to
have elevated activity, unless referring to the regulations of a specific state. Table 6-13 provides a
summary of the different terminology typically used by different states in regulatory text.
Table 6-13. Summary of Terminology for Radioactivity
Terminology Specific State
NORM AR, IL, IN, MS, NM, TX, WY
TENORM KY, MT, ND, NY, VA, WV
NARM FL, NY, NV, TN
NORM and TENORM CO, ID, OH, PA
Naturally Occurring Material MI

Radiation Regulations: Most of the states reviewed (22 of 28) address radioactivity somewhere in the
state regulations. Only ten states discuss radioactivity within the E&P regulations, though some
(e.g., Tennessee) simply refer back to the state’s radiation regulations. Of the top five producing states
(i.e., Texas, Pennsylvania, Alaska, Oklahoma, North Dakota), Texas and North Dakota have the most
extensive regulations. Pennsylvania requires a comprehensive radioactive material action plan for any
onsite treatment of fluids or drill cuttings. Alaska and Oklahoma do not specifically address this topic.
In nearly all of the states, primary responsibility for regulating TENORM lies with the state health

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-27

department (ten states) or environmental agency (includes solid waste agencies). For example,
radioactivity in New Mexico is regulated by the Oil and Gas Conservation Division, and Texas is
regulated primarily by the Railroad Commission and supported by the Department of State Health
Services. Texas regulations include a clear and comprehensive description of the jurisdiction of the two
agencies. The delineation of roles is less clear in the regulations of other states with split jurisdiction,
though several states (e.g., Colorado, North Dakota) provide fact sheets to help operators navigate the
regulations. Because of the fragmented nature of E&P regulations on radioactivity, it was challenging
to construct a complete picture of the coverage of all aspects of regulation across the country.
EPA found that state regulations touch on a wide range of issues including planning requirements,
operational activities at the well or production site, closure activities, or characterization and disposal
(includes onsite, downhole and offsite landfills). However, few states cover all these areas and the
relevant regulations are often scattered across different agencies and sections of regulatory text. The
most comprehensive regulations related to solid waste landfill requirements and downhole well
disposal. A few states addressed radioactivity associated with waste management unit operation and
closure.
Action/Management Plan: Four states (i.e., Illinois, Indiana, Louisiana, New Mexico) require an
action/management plan to manage radioactivity, but the required content varies. For instance, in
Illinois, E&P waste is considered low-level radioactive waste and disposal is managed under the Central
Midwest Interstate Low-Level Radioactive Waste Commission Regional Management Plan, but a site-
specific action plan addressing handling and testing of E&P waste is required as part of the Illinois oil
and gas permitting regulations. The Action Plan required in Pennsylvania, however, is specific to oil
and gas operations and must include procedures for monitoring and responding to radioactive materials
produced by the treatment process and procedures for training, notification, recordkeeping and
reporting. Some states appear to require action or management plans as part of the radiation safety
protection regulations (under the public health division or solid waste division) but it is often unclear
how or if these regulations apply to operation and disposal at oil and gas operations.
Storage Requirements: Eight states include some type of storage requirements for NORM/TENORM
wastes. For example, North Dakota provides detailed requirements for management and inspection of
containers and tanks containing TENORM waste. Wyoming guidelines indicate NORM wastes “should
be stored in enclosed containers, durable synthetic fiber ‘super sacks’ or equivalent” for periods not to
exceed 90 days, 180 days or up to 1 year depending on the activity and volume of the waste. In addition,
West Virginia requires an annual registration form and Arkansas refers to general “NORM radiation
requirements” for storage.
Disposal Screening: Eleven states require screening for radioactivity prior to disposal either onsite or
at the landfill. Although many regulations do not provide detailed requirements for testing, New York
includes a specific regulation for screening when cuttings with NORM/TENORM are disposed.
Pennsylvania requires radiation testing for disposal at offsite municipal landfills but not for
NORM/TENORM wastes specifically. While Colorado does not require screening at the landfill prior

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-28

to disposal, testing of each waste shipment by the facility generating the waste is required prior to
transport. Illinois and several other states require testing of soil and residues before pit closure. Site-
specific landfill permits may include requirements for screening of incoming materials for radioactive
materials or provide specific acceptance criteria.
Disposal Options: Most states (23 of 28) discuss disposal options for these wastes, which may vary
depending on waste activity. The most common option is offsite disposal at facilities permitted for
general radioactive waste or more specific NORM/TENORM. Disposal at solid waste or hazardous
waste facilities is allowed in some states in accordance with specific thresholds. Other options include
downhole injection, land spreading, onsite burial and reuse. Some states may allow more than one type
of disposal. Ohio regulations, for instance, state “lawful disposal” of wastes is required, which may
include reuse, injection and out-of-state disposal. Florida regulations are complex but appear to allow
NORM/TENORM disposal by a variety of methods.
Administrative requirements such as notification, reporting and permitting also vary by state. For
example, Indiana regulations require notification and a disposal plan but not a permit for NORM
disposal. Permits are required for disposal in some states, such as Mississippi and New York. In New
York, no permit is required for disposal of NORM but disposal of TENORM is highly restrictive. States
governed by interstate agreements or compacts for low-level radioactive waste often include an
additional layer of regulations regarding import and export of radioactive materials for disposal.
Disposal Limits: Nearly all (20 of 23) states that explicitly allow disposal present activity limits. Based
on the regulations reviewed, numerical thresholds typically range from 3 picocuries per gram (pCi/g)
of 226+228Ra (Colorado) to 200 pCi/g 226+228Ra (Kentucky). In many states, wastes classified as NORM are
exempt from regulations if the materials contain concentrations less than 5 pCi/g of 226+228Ra or
100 pCi/g of other naturally occuring radionuclides. Colorado currently has three landfills permitted
for TENORM disposal with different acceptance criteria, while solid waste facilities may be used only
if stringent testing and radioactivity criteria are met.
The type of facility where disposal is allowed may depend on the waste activity. Wyoming regulations
allow disposal at a solid waste facility for waste up to 50 pCi/g 226Ra while wastes with levels greater
than 50 pCi/g 226Ra must be managed at out-of-state facilities authorized to accept low-level radioactive
waste. In Michigan, disposal of waste up to 50 pCi/g 226Ra is allowed in a hazardous waste or Type 2
landfill, but wastes greater than 50 pCi/g 226Ra must be disposed in a licensed radioactive waste facility.
No limits are presented for downhole disposal of waste.
Conclusions
The review of state regulatory programs focused on 61 specific elements organized into 12 general topic
areas. Each of these elements (e.g., location restrictions, inspections) was chosen based on a review of
existing federal solid waste management programs. The selected elements are those that EPA considers
to be broadly applicable, regardless of waste type, and so provide a reasonable basis for comparison
among different programs. Yet the absence of a particular element in this review does not necessarily

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-29

mean a state program is deficient. Some states may not address a particular practice in regulations
because issues are handled on a case-by-case basis (e.g., beneficial use) or the practice is does not occur
within the state boundaries (e.g., centralized pits). In some cases, professional judgment was required
to interpret how regulatory language would be implemented by the relevant state agencies. It is possible
that separate guidance documents and individual permits further elaborate on requirements in the
regulatory text; however, these documents may not be posted publicly or may require foreknowledge
of specific wells or management units to locate. Therefore, this regulatory review, while not fully
comprehensive, does provide a great deal of information about the scope of coverage (e.g., the wastes
and activities), and the level of detail and precision in the requirements to determine where these
programs are equivalent to or expand upon current RCRA Subtitle D requirements.
EPA reviewed the text of regulations from 28 of the 34 states with reported production of oil and gas
tracked by the EIA. Together, these states represent over 99% of the total oil and gas production in the
United States. Table 6-14 provides a summary of the states reviewed, organized by the estimated
percent of national crude oil and natural gas production in 2016 (by volume expressed in barrels).
Table 6-14. Ranking of State Oil and Gas Production
Percent
Production State Percent
Production State Percent
Production State Percent
Production State
32.0% Texas 4.6% New Mexico 1.0% Kansas 0.04% Indiana
11.5% Pennsylvania 4.4% Louisiana 0.4% Montana 0.04% New York
8.4% Alaska 3.4% Ohio 0.4% Mississippi 0.03% Florida
7.3% Oklahoma 3.1% West Virginia 0.3% Michigan 0.01% Idaho
6.0% North Dakota 2.8% California 0.3% Virginia 0.01% Tenessee
5.1% Colorado 1.8% Arkansas 0.2% Kentucky 0.01% Nevada
4.9% Wyoming 1.2% Utah 0.1% Illinois 0.01% Missouri

Generally, EPA found that state regulatory programs for E&P waste include a majority of the elements
relevant to the management of solid wastes. The scope and specificity of regulatory programs varied
among states; however, some general trends were observed relative to the amount of oil and gas
production in the states. The 11 highest-producing states account for more than 90% of national
production. These states tend to have regulatory programs tailored specifically to the management of
E&P wastes, which can include specific requirements by well type (e.g., conventional,
unconventional), waste type or management practice. These states are also more likely to have
centralized infrastructure dedicated to the storage and disposal of E&P wastes mainly due to the sheer
volume of waste generated and the possibility of overwhelming the capacity of other disposal options
(e.g., municipal solid waste landfill). The remaining 17 states account for around 9% of total oil and gas
production. It appears that these states tend to have more general programs that address E&P waste
management under the same or similar regulatory framework as other non-hazardous solid wastes.
These states are more likely to manage E&P wastes, as appropriate, within existing landfills and may
not have requirements that specifically reference E&P wastes. Table 6-15 provides a summary of the
prevalence of each element in state programs based on Agency review. Each specific regulatory
elements within a topic area is ordered from greatest to least coverage.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-30

Table 6-15. Summary of State Program Regulatory Elements
General
Topic Specific Element
Percent of
National
Production
State
Count
1
Consistency with 40 CFR Part 257.3 – Coverage
1) Groundwater 94% 25
2) Surface Water 94% 24
3) Floodplains 93% 23
4) Endangered Species 31% 9
2
Waste Management Location Requirements (Siting and Setbacks)
5) Environmental Receptors (Surface Water, Wetlands, Watercourses) 91% 22
6) Residential 73% 17
7) Depth to Groundwater 42% 13
3
Tank Requirements (Onsite/On-Lease)
8) Tank Berms and Containment Specifications 74% 18
9) Requirements for Tank Construction Material 50% 11
10) Tank Bottom Removal Permit Required 50% 4
11) Netting for Open Tanks Required 46% 7
12) Requirements for Modular Large Volume Tanks 18% 2
13) Tank Monitoring Required 12% 4
4
Pit Construction and Operation Requirements
14) Requirements for Pit Liners 99% 27
15) Multiple Pit Content/Use Types Specified 88% 23
16) Temporary Pit Requirements 88% 17
17) Requirements for Fencing 87% 18
18) Freeboard Requirements 86% 20
19) Berm Requirements 84% 17
20) GW Monitoring Required 81% 15
21) Run-On and Run-Off Controls 80% 19
22) Inspections 74% 11
23) Discharge Permits Required 72% 11
24) Permit Required 70% 16
25) Prohibited Pits 69% 13
26) Non-Commercial Fluid Recycling Pits 62% 5
27) Netting 57% 11
28) Leak Detection/Monitoring Required 55% 10
29) Depth to Groundwater Specified (Minimum) 40% 12
30) Centralized Pits 37% 6
31) Pit Signage 27% 7
5
Pit Closure Requirements
32) Liquids Removal Required 87% 23
33) Closure Schedule Specified 85% 22
34) Inspections Required 71% 10
35) Solids Removal Required 64% 17
36) Sampling Required 55% 8
37) Financial Security Required 3% 1

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-31

Table 6-15. Summary of State Program Regulatory Elements
General
Topic Specific Element
Percent of
National
Production
State
Count
6
Spill Notification and Corrective Action
38) Spill Notification Required 91% 26
39) Corrective Action Plan Required 78% 20
7
Offsite Landfills
40) E&P Waste Allowed in Offsite Landfills 99% 25
41) Testing of Waste Required 51% 7
42) Use of E&P Wastes as Daily Cover Allowed 7% 2
8
Land Application
43) Land Application Allowed 81% 17
44) Specific Limitations/Conditions for Land Application 79% 16
45) Location Restrictions 69% 14
9
Beneficial Use
46) Road Spreading Allowed (Specify if Permit is Required) 68% 11
47) Testing Requirements for Beneficial Use 64% 10
48) Specific Limitations/Conditions for Road Spreading 62% 9
10
Waste Minimization and Best Management Practices
49) Closed Loop Drilling Requirements 25% 7
50) Produced Water Recycling Requirements 0% 0
11
Commercial On/Off Lease and Stationary Recycling/Reclamation Facilities
51) Commercial Facilities Regulated (Specify if Permit is Required) 58% 7
52) Financial Security/Closure Required 50% 4
53) Offsite Reclamation Manifest Required 50% 4
54) Monitoring and Testing Required During Operation 50% 4
12
NORM and TENORM
55) State Regulations Address Radioactivity 79% 22
56) Disposal Allowed 71% 23
57) Disposal Limitations and Conditions 67% 20
58) Onsite or Landfill Testing/Screening Required 60% 11
59) E&P Waste Regulations Address Radioactivity 47% 8
60) Storage Requirements 28% 8
61) Action Plan/Management Plan Required 9% 4

The level of coverage for each element is variable. This is expected, as the scope and specificity of state
programs can vary in response to regional factors that impact the types of waste generated and the
appropriate methods to manage those wastes. However, several elements are present in regulations for
nearly every state reviewed. Many of these elements are more standardized requirements intended to
either prevent releases to the environment (e.g., pit liners) or ensure that releases are identified and
addressed (e.g., spill reporting, groundwater monitoring). Other elements have substantial coverage,
but from a relatively small number of states, which indicates these elements (e.g., centralized disposal)
are concentrated states with higher production. The elements with the lowest coverage (e.g., tank
signage, financial assurance, produced water recycling) tend to be those that do not directly address

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-32

potential environmental releases, but are considered best management practices. There is no indication
from this review that there are widespread gaps in the scope of the written regulations. Any gaps that
are identified for individual states might be better addressed through outreach and other targeted
actions.
States have continued to periodically update regulatory programs that address issues raised by increased
production, emerging environmental issues, and ongoing reviews from third parties. At least 24 states
out of the 28 reviewed have revised their regulations related to E&P wastes in the past six years, with
some revisions as recent as 2018. Table 6-16 provides a summary of the most recent updates for each
state.
Table 6-16. Most Recent Updates to State Programs
State Percentage of
Production
Most Recent Updates
Identified
Texas 32.0% 2013
Pennsylvania 11.5% 2016
Alaska 8.4% 2017
Oklahoma 7.3% 2017
North Dakota 6.0% 2015
Colorado 5.1% 2016
Wyoming 4.9% 2016
New Mexico 4.6% 2016
Louisiana 4.4% 2014
Ohio 3.4% 2005
West Virginia 3.1% 2016
California 2.8% 2015
Arkansas 1.8% 2012
Utah 1.2% 2016
Kansas 1.0% 2013
Montana 0.4% 2018
Mississippi 0.4% 2015
Michigan 0.3% 2015
Virginia 0.3% 2016
Kentucky 0.2% 2007
Illinois 0.1% 2014
Indiana 0.04% 2017
Florida 0.03% 2013
New York 0.04% Unknown
Idaho 0.01% 2015
Tenessee 0.01% 2013
Nevada 0.01% 2014
Missouri 0.01% 2016

Based on this review, EPA concludes that the scope and specificity of regulatory programs varies among
the states based on a number of factors, such as the quantity of oil and gas produced in the state and
the prevalence of hydraulically fractured wells. Despite this variability, the existing state programs
incorporate a majority of elements found in federal waste management programs, which indicates that

Management of Oil and Gas Exploration, Development and Production Wastes
Section 6: State Programs 6-33

the scope of the written state regulations is robust. However, the way in which these regulations are
interpreted and implemented are also important considerations. To better understand which practices
may pose concern, EPA reviewed the assembled literature for existing evaluations that had drawn
conclusions about the potential for adverse effects from management of E&P wastes.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-1

7. Review of Existing Evaluations
EPA reviewed the available literature to identify evaluations that had previously quantified the risk of
adverse effects associated with the management of E&P wastes. The purpose of this review was to
determine whether the data and analyses that underpin the findings of these evaluations are of
sufficient quality to draw conclusions about the current management practices. EPA identified two
evaluations that provide quantitative estimates of potential risk:
 Technical Support Document Onshore Oil and Gas Exploration, Development, and Production:
Human Health and Environmental Risk Assessment (U.S. EPA, 1987d)
 Potential Radiological Doses Associated with the Disposal of Petroleum Industry NORM via
Landspreading (U.S. DOE, 1998)
EPA reviewed the data relied upon and analyses conducted for these evaluations to identify any major
sources of uncertainty. Moreover, EPA considered how the information that has become available since
the completion of these evaluations might affect reported risks. Based on this review, EPA determined
whether these evaluations support any conclusions about the types of management practices that could
result in adverse effects.
U.S. Environmental Protection Agency (1987d)
In the 1987 Technical Support Document Onshore Oil and Gas Exploration, Development, and
Production: Human Health and Environmental Risk Assessment (1987 TSD; U.S. EPA, 1987d), EPA
evaluated the risks that might result from the management of E&P wastes from exploration and
production. The potential release routes examined were leaching from pits with and without liners and
caps, inadvertent discharges to groundwater through well failure and direct discharges to surface water
from wells. The following discussion focuses only on waste management in pits. Discharges from waste
management units to water bodies are classified as point sources and regulated under the Clean Water
Act. Disposal through injection wells is regulated under the Safe Drinking Water Act. Therefore, these
management practices are not further discussed in the context of RCRA.
7.1.1. Evaluation Summary
To characterize wastes generated for the 1987 TSD, EPA initially collected 100 samples of drilling and
production waste from 49 sites across the country. Sampling locations included centralized treatment
facilities (3 sites), central disposal facilities (4 sites), drilling operations (19 sites), and production
facilities (23 sites). EPA analyzed the collected samples for 534 constituents and parameters that
included 444 organic compounds, 68 inorganic elements, 19 water quality parameters, and 3 RCRA
characteristics.20 EPA initially limited the quantitative evaluation to 36 inorganic elements and 25
organic compounds based on frequency of detection in waste samples and availability of toxicity values.

20) Water quality parameters include pH, total suspended and dissolved solids and biological oxygen demand. RCRA characteristics
include corrosivity, ignitability and reactivity.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-2

This list was then further refined based on anticipated mobility of constituents in groundwater
(i.e., likelihood to reach receptors). Constituents ultimately retained for fate and transport modeling
included benzene and arsenic for cancer risk; cadmium, chromium and sodium for noncancer risk; and
boron, cadmium, chloride, chromium and sodium for aquatic toxicity and environmental resource
damage.
The 1987 TSD modeled fate and transport from pits. A range of disposal unit sizes and distances to
receptors were considered. Risks were found to be below levels of concern for all modeled exposure
scenarios. For waste disposed in reserve pits, the majority of modeled cancer risks were less than 1×10-
7 and none were greater than 1×10-5. Only two percent of model runs for unlined pits resulted in
noncancer risks from sodium. However, EPA concluded that the high salt content of produced waters
would result in noticeable and unpleasant changes to the taste of water concurrent with any elevated
risks, which would alert residents and limit exposures.
7.1.2. Uncertainties
As with any evaluation, there are uncertainties associated with the 1987 TSD. Some may arise from the
practical limitations of models and data available at the time, while others are driven by changes to
industry practices in the decades since the evaluation was finalized. The following discussion
summarizes key uncertainties identified during this review and, where practicable, how consideration
of more recent data might affect the evaluation findings.
Waste Types Evaluated
The reserve pits modeled in the 1987 TSD contained wastes generated from drilling with water-based
fluids. The main types of waste managed in these pits are cuttings and drilling mud. There are a number
of other wastes generated during exploration and production (e.g., produced water, sludge) and, as
shown in this document, these wastes may contain higher concentrations of some constituents than
drilling solids. EPA acknowledged in the 1987 TSD that these other wastes might potentially result in
adverse effects to human health and the environment. However, the Agency did not have adequate
data at the time on the chemical composition, sources, volumes and management practices for these
other waste types to permit evaluation of the associated risks. As a result, no conclusions can be drawn
from this evaluation about the risks associated with these additional wastes.
Waste Composition
The largest shift in drilling practices in the past three decades has been the adoption of directional
drilling. Although hydraulic fracturing has been used since the 1950s, the practice was not as
widespread until the 2000s when advances in directional drilling allowed greater access to formations
that had been previously deemed uneconomical (Soeder et al., 2014). This shift in drilling practices
resulted in greater volumes of waste due to the greater distance drilled and the large volume of water
needed for fracturing. To better understand the extent to which the composition of these wastes may
also have changed since 1987, EPA compared the constituent concentrations used in the 1987 TSD and
those assembled in the current E&P database.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-3

In 1986, EPA was able to sample only a limited number of facilities due to time and resource constraints.
To provide a best estimate of typical waste concentrations from these samples, EPA first weighted
selection of sample locations based on indicators of waste generation from previous reports. Drilling
site selection was weighted based on total wells drilled in each state, while production site selection
was weighted based on annual hydrocarbon production in each region. Samples from the north slope
of Alaska were omitted from summary statistics because this region was handled in a separate
qualitative evaluation.
The current produced water dataset is based on a review of available literature and so the Agency did
not have any control over the type or number of samples available. This resulted in uneven sampling
in different regions of the country. Therefore, EPA weighted the available data by the annual
hydrocarbon production in each region of the country. All samples within a given region were given
the same weight. Table 7-1 provides a comparison of the 50th and 90th percentile concentrations from
vertical wells in the 1987 TSD and horizontal wells in Pennsylvania (the only state with data available)
in the current dataset.
Table 7-1. Comparison of Constituent Data for Produced Water
Constituent
1987 Vertical Data Current Vertical Data Current Horizontal Data
N 50th 90th N 50th 90th N 50th 90th
Arsenic 9 / 24 0.02 1.7 51 / 65 0.01 0.20 -- -- --
Benzene 16 / 21 0.47 2.9 27 / 32 0.23 4.9 -- -- --
Boron 24 / 24 10 120 1,369 / 1,370 39 115 192 / 195 21 46
Chloride 21 / 21 7,300 35,000 39,766 / 39,766 27,500 132,048 291 / 291 71,200 132,000
Sodium 24 / 24 9,400 67,000 39,138 / 39,138 15,375 62,678 291 / 291 34,700 52,322
N – Detection Frequency

The two vertical datasets ostensibly reflect the same waste and so should be similar if all sources of
variability have been captured. Both high-end and median concentrations of benzene, boron and
sodium are similar and median concentrations of arsenic are similar. The similarities between the two
datasets provides some confidence that the overall distributions for these constituents. The greatest
difference between the datasets is chloride. It is not clear why chloride in the 1987 TSD is lower than
both chloride in the current vertical dataset and sodium in the same dataset. This indicates that the
1987 TSD may underestimate concentrations of certain constituents.
The current dataset for drilling fluid was assembled through the same literature review as produced
water. However, unlike produced water, there was not sufficient data from across the country to weight
the data by region to obtain a more representative national distribution. Instead, EPA conducted a more
limited comparison with horizontal data from a single state. Table 7-2 provides a comparison of the
50th and 90th percentile concentrations contained in the 1987 TSD and the current dataset for
horizontal wells in Pennsylvania.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-4

Table 7-2. Comparison of Constituent Data for Drilling Fluid
Constituent
1987 Vertical Data Current Horizontal Data
N 50th 90th N 50th 90th
Arsenic 6 / 17 ND 0.16 12 0.03 0.18
Cadmium 13 / 17 0.04 1.4 -- -- --
Chloride 17 / 17 3,500 39,000 35 17,000 89,000
Chromium 14 / 17 0.43 290 13 / 21 0.25 1.3
Sodium 17 / 17 6,700 44,000 33 11,400 33,900
N – Detection Frequency
ND – Non-Detect

Some of the trends observed for produced water are also present in the data for drilling fluid. Both
high-end and median concentrations of arsenic and sodium are similar, while chloride concentrations
in the 1987 TSD are lower than both the current dataset and sodium in the same dataset. Chromium is
substantially higher in the 1987 TSD, which might be attributed to the additive chrome lignosulfonate
that was historically used to deflocculate clay particles and to reduce fluid viscosity (NRC, 1983). There
are reports that this additive is used less frequently in current drilling operations and is often replaced
by iron or calcium lignosulfonate (Schlumberger, 2018). However, to the extent the chromium-based
additive is still used, the current dataset may underestimate chromium concentrations.
Based on this comparison of datasets, EPA concludes there is general agreement between the two
datasets for several constituents. Other constituents were found to be higher or lower in the 1987 TSD,
though there is no evidence of a consistent bias in either direction. The greatest difference between
the datasets is for chloride. It might be possible that lower chloride levels in the 1987 TSD are the result
of analytical error due to improper calibration for high concentrations. There is not enough data
available to determine whether other constituents that have a strong relationship with chloride
(e.g., strontium) are also lower in this dataset. This remains a source of uncertainty.
Additional Constituents
The 1987 TSD analyzed for 444 organic compounds. A majority of these compounds were not detected
in any samples. However, some were later detected at low concentrations in more recent studies. It is
possible that the 1987 TSD failed to identify some compounds present because of higher detection
limits. It is also possible that some of these compounds were not present in 1987 and were introduced
into recent samples by hydraulic fracturing additives. Between 1,400 to 2,500 compounds have been
tentatively reported in samples of produced water by different studies. Some of the compounds detected
in recent studies were not analyzed for in the 1987 TSD. Therefore, there is potential for additional
risks from additives that were not considered in the 1987 TSD.
The 1987 TSD did not address radiation from E&P wastes. Public health concerns were initially raised
when pipe scale with high activity was identified in drilling equipment around the Gulf Coast (API,
1989). EPA began efforts to characterize the occurrence and potential impacts of NORM and TENORM
in the late 1980s (U.S. EPA, 1993). A draft report was reviewed by the EPA Science Advisory Board
(U.S. EPA, 1994), but was not finalized based on the need for additional data to address remaining

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-5

uncertainties. Around the same time, several states began to collect data on radioactivity in E&P wastes
(e.g., WVDEQ, 1990; MIDNR/DPH, 1991; TXBEG, 1995; CADHS/DC, 1996; NYDEC, 1999). To assist
states with the management of these and other TENORM wastes, the Conference of Radiation Control
Program Directors developed suggested regulations (Part N) that address a structure for licensing
programs, worker protection, release limits and conditions for regulatory exemption. These suggestions
have been revised and updated on an ongoing basis, most recently in 2004. A number of states have
incorporated these suggestions into regulatory programs for E&P wastes (ASTSWMO, 2015). Further
discussion of state regulations is provided in Section 6 (State Programs). However, renewed concerns
have recently arisen due to the expansion of directional drilling (e.g., U.S. DOE, 2014; WVDEP, 2015;
PADEP, 2016). Both the increased waste volume and the potential for higher activities pose additional
management challenges. To understand whether and how recent changes in drilling practices might
affect the composition of E&P waste, EPA compiled data on radioisotope activities in the E&P Database.
The available data indicate that elevated activities of uranium or radium can be present in waste from
both vertical and horizontal wells. These elevated activities are not isolated to specific formations and,
thus, are likely to have been present at similar levels in samples analyzed for the 1987 TSD.
Model Duration
The 1987 TSD refined the ultimate list of constituents evaluated based on mobility in the environment,
focusing on those anticipated to reach receptor wells within 200 years of the initial release. Wells were
assumed to be present at distances of 60, 200, and 1,000 meters away from waste pits. This constraint
resulted from limitations in the Landfill Liner Model. More recent model runs with the EPA Composite
Model for Leachate Migration with Transformation Products on coal ash ponds found that that median
time for peak concentrations of arsenic to reach the nearest wells at similar distances ranged from 2,000
to 10,000 years, depending on chemical speciation (U.S. EPA, 2014d). The results of this risk assessment
cannot be directly transposed onto E&P wastes. However, it is clear that the 200-year limit is likely to
underestimate potential long-term risks.
Constituent Mobility
Partitioning coefficients (Kd) are ratios of constituent mass that is bound to the soil and dissolved in the
aqueous phase at equilibrium. Higher values reflect greater retention on the soil and lower mobility
through the subsurface. In the 1987 TSD, EPA reviewed the available literature to identify values for
each modeled constituent and selected single values intended to be representative for each constituent.
However, partitioning coefficients can be affected by a number of environmental factors that are not
constant. Some key factors known to affect Kd values include the concentration of the constituent in
groundwater, the pH and ionic strength of the solution, the degree of soil saturation, and the type and
amount of different sorbents present within the aquifer.
EPA developed the Metal Speciation Equilibrium for Surface and Ground Water Model in 1999 to
calculate Kd values for a wider range of environmental conditions and provide a better estimate of
constituent mobility for different types of waste (U.S. EPA, 1999a). The most recent version of this
model was released in 2006 (Version 4.03). To understand the extent to which single Kd values may
overestimate or underestimate constituent mobility, EPA compared values used in the 1987 TSD with

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-6

those calculated for municipal solid waste landfills (U.S. EPA, 1999b) and coal combustion residual
(CCR) landfills (U.S. EPA, 2014d). These calculated values incorporate variability from different aquifer
pH, ionic strength, organic matter and iron oxide sorbents. Because these values can vary widely on a
national-scale, EPA selected high and low bounds for comparison. Table 7-3 presents the result of this
comparison. It is anticipated that E&P wastes will most closely resemble CCR data because of the
similarly high ionic strength of the wastes.
Table 7-3. Comparison of Saturated Zone Partitioning Coefficients (ml/g)
Constituent 1987 TSD
Municipal Solid Waste CCR Waste Landfill
Low High Low High
Arsenic (III)
Unsaturated
5.0
5×10-3 3.0 9×10-8 0.64
Saturated 2×10-3 3.0 5×10-7 1.1
Arsenic (V)
Unsaturated
5.0
0.2 10,000 1.9 1,100
Saturated 0.6 10,000 1.0 450
Boron
Unsaturated
3.0
-- -- < 1×10-10 0.80
Saturated -- -- 1×10-6 3×10-5
Cadmium
Unsaturated
6.5
0.1 10 < 1×10-10 2.3
Saturated 0.1 3.0 0.2 7.3
-- Constituent not modeled

In several cases, the entire range of modeled Kd values are lower than the individual value used in the
1987 TSD, often by several orders of magnitude. The major exception is arsenic (V), which ranges from
slightly lower to several orders of magnitude higher. Based on this comparison, the groundwater model
in the 1987 TSD will tend to underestimates the potential mobility of the modeled constituents.
7.1.3. Findings
U.S. EPA (1987d) found limited potential for risk from disposal of drilling solids in pits. However, there
are several uncertainties associated with the analysis conducted that may, on the whole, result in an
underestimation of risk. The greatest uncertainties are waste types, management practices, constituents
and release pathways that could not be evaluated due to a lack of data. The extent to which the analysis
might underestimate actual risks is not clear and EPA did not attempt to update the model results as
part of this review. A number of states now have regulations in place that require use of liners and
other controls for pits that would potentially mitigate releases from these wastes. Therefore, there is
not enough information available from this existing evaluation to draw conclusions about the current
disposal practices for E&P wastes.
U.S. Department of Energy (1998)
In 1998, the U.S. DOE Argonne National Lab modeled exposures that may result from land application
of E&P wastes that contain TENORM. This report expands on previous analyses reported in Smith et
al. (1995). The practice of disposing of E&P waste in surface soil has been referred to by various terms
that describe a range of practices with substantial overlap (e.g., landspreading, landfarming, land
application, land treatment). These practices may involve spreading waste on top of the soil or mixing

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-7

it into the soil column. Application of the waste may occur all at once or in multiple iterations. The
primary goal of these disposal practices is the natural attenuation of organic compounds combined with
the dilution and immobilization of other contaminants. To this end, nutrients or other soil amendments
may be spread along with the waste to promote degradation of organics and the soil may be periodically
tilled to improve aeration (API, 2000).
Surface disposal is generally limited to solid or semi-solid wastes such as drill cuttings, pipeline scale
and pigging waste, tank and pit sludges, and contaminated soil. Surface disposal of one or more of these
wastes at offsite facilities has been reported in at least 11 states (U.S. DOE, 2006). However, this is not
assumed to be a comprehensive list because it is based on voluntary responses and does not include
onsite disposal. The most common restrictions identified during the review of state programs involve
the levels of chloride or TPH in the waste or the resulting soil-waste mixture. Some states also include
restrictions on the activity of radioisotopes with limits set anywhere from 5 pCi/g above background
to 30 pCi/g total activity, though a number of states have no documented limits. Further discussion of
state-specific regulations is provided in Section 6 (State Programs).
7.2.1. Evaluation Summary
Argonne National Laboratory used RESRAD (Version 5.782) to model the doses that may result from
direct gamma exposure, inhalation of radon, and ingestion of local soil and produce. The evaluation
considered multiple receptors that include residents, industrial workers and recreational users. The
most significant differences between the modeled receptors is which exposure pathways are complete
(e.g., ingestion of local produce) and the duration of exposure. The primary radionuclide of concern
modeled in the evaluation was radium because these radioisotopes and the immediate progeny are those
most likely to concentrate in these wastes and drive risk. Because exposures to radiation can be scaled
based on the activity present, the evaluation used a unitized activity of 1 pCi/g 226Ra. The immediate,
short-lived progeny (half-life less than a year) were assumed to be in secular equilibrium with the
applied radium. To address uncertainty about the final soil activity, ANL modeled doses were adjusted
to values ranging between 5 and 2,000 pCi/g 226Ra. As part of a sensitivity analysis, additional
contributions from 228Ra were estimated as 30% of the activity of 226Ra.
U.S. DOE (1998) found that a surface soil activity of 5 pCi/g 226Ra above background resulted in an
additional 30 mrem/yr exposure from gamma radiation. Radon accumulation in the home increased
the modeled doses to 60 mrem/yr. All other pathways contributed less than 5% to the total dose. Based
on these results, the authors recommended that states that allow landspreading of E&P waste to
activities greater than 5 pCi/g above background should consider establishing policies that will restrict
future land use or, at a minimum, ensure that future land owners are advised of the activities and the
potential associated health risks.
7.2.2. Uncertainties
As with any evaluation, there are uncertainties. Some may arise from the practical limitations of models
and data available at the time, while others are driven by changes to the industry practices in the
decades since the evaluation was finalized. The following discussion summarizes key uncertainties

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-8

identified during this review and, where practicable, how consideration of more recent data might alter
the evaluation findings.
Total Radium
The lowest identified state limits of 5 pCi/g reflect the combined contributions from 226Ra and 228Ra.
U.S. DOE (1998) did not account for this limit on combined activities. Instead the authors assumed that
the activity of 228Ra was a third of the longer-lived 226Ra isotope. Therefore, a 226Ra activity of 5 pCi/g
would result in a total activity of approximately 6.7 pCi/g 226+228Ra. This has the potential to result in an
overestimation of risk in areas where such limits are enforced.
Erosion
ANL assumed a uniform rate of erosion of approximately 0.04 in/yr that resulted in the eventual
depletion of both topsoil and applied waste over time. This rate of soil erosion may occur around fields
that are in active rotation where the soil is periodically disturbed, but may overestimate losses in areas
adjacent to and particularly underneath a building. The presence of continuous vegetation and man-
made structures that shield the soil will limit erosion from wind and encourage suspended soil particles
to settle out of overland runoff. Thus, the assumed rate of erosion may underestimate long-term risks.
Dose
ANL compared modeled doses to the National Council on Radiation Protection and Measurements
recommended annual dose limits for the general public of 100 mrem above background and concluded
that exposures below 5 pCi/g were generally acceptable. The use of dose does not provide information
about the magnitude of excess cancer risk. A dose rate of 100 mrem would result in risks considerably
higher than the upper bound of the risk range used by RCRA of 1×10-6 to 1×10-4. Differences between
dose and risk are attributable to how competing mortality risks and age-dependent radiation risk
models are handled, the weighting of individual organs, as well as other dosimetric and toxicological
assumptions (U.S. EPA, 1999c; 2014e; ISCORS, 2002). ANL did attempt to translate modeled doses to
risk of fatal cancer based on conversion factors developed by the International Commission on
Radiological Protection (ICRP, 1991). However, the risk of fatality will always be lower than the risk
of cancer incidence that is the basis for the RCRA risk range.
7.2.3. Updated Analysis
The review of the previous analysis indicates that some assumptions may overestimate or underestimate
the magnitude of exposures on a case-by-case basis, though the largest uncertainty is the use of dose.
Therefore, EPA updated the analysis with current models and data to estimate potential risks. EPA used
RESRAD-OFFSITE version 3.2 (U.S. NRC, 2013) because the similar model framework allows a more
direct comparison with the previous model results.21 The current version of RESRAD calculates risk
with cancer slope factors based on the data from Biological Effects of Ionizing Radiation (BEIR) VII
Phase 2: Health Risks from Exposure to Low Levels of Ionizing Radiation (NRC, 2006). This allows a
direct comparison of results using the RCRA risk range. EPA selected model inputs based on data from

21) Use of this model does not represent an endorsement by EPA for use in other applications. EPA offices may evaluate similar
exposure scenarios with other models based on the specific needs and requirements of each program.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-9

the literature and Agency documents. For some inputs, particularly those related to waste properties
and building design, insufficient data are available to construct full distributions. Instead, EPA selected
high and low values to provide a bounding analysis. For inputs based on policy or that are considered
less variable, EPA selected a single value to manage the number of model runs required. Table 7-4
presents a comparison of data used in the current analysis and U.S. DOE (1998).
Table 7-4. Comparison of Inputs for RESRAD Model
Parameters Current U.S. DOE (1998)
Human Exposure Factors
Fraction of Time Spent Indoors (%) 0.8 0.5
Fraction of Time Spent Outdoors (%) 0.096 0.25
Exposure Duration (years) 48 30
Inhalation Rate (m3/day) 23 23
Waste Characteristics
Radium Isotopes Ratio (228R/226Ra) 0.33 - 3.0 0.3
Radon emanation coefficient (unitless) 0.05 - 0.22 0.04
Application Depth (m) 0.02 - 0.2 0.2
Application Area (m2) 4,047 8,093
Building Characteristics
Residential Air change per hour (1/hr) 0.18 - 1.26 0.5
Room Height (m) 2.7 2.5
Room Area (m2) 100 100
Floor Thickness (m) 0.13 0.15
Effective radon diffusion coefficient of floor (m2/s) 2.1×10-8 - 5.0×10-6 3.0×10-7
Density of floor and foundation (kg/m3) 2,600 2,000
Total porosity of floor and foundation (unitless) 0.16 0.10
Gamma Shielding Factor (unitless) 0.2 - 0.7 0.7

The total range of values can sometimes span multiple orders of magnitude. This is because the current
evaluation aims to provide both an upper and lower bound on highly exposed individuals. However,
many of the selected values are similar to or encompass those used in the 1998 analysis. Further
discussion of each variable and the data sources is provided below:
 Inhalation Rates is the volume of air inhaled by an individual over a specified period of time. It
determines the amount of radon taken into the lungs. The selected value is a weighted average of
the 95th percentile inhalation rates for adults between the ages of 16 and 71 years old reported in
Table 6-16 of the 2011 Exposure Factor Handbook (U.S. EPA, 2011).
 Exposure Duration is the number of years that the receptor lives at a single residence. It
determines the total amount of time a receptor is near the waste and potentially exposed. The
selected value is the 90th percentile for resident farmers from Table 16-92 of the 2011 Exposures
Factors Handbook (U.S. EPA, 2011).

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-10

 Time Spent Indoors/Outdoors is the fraction of a day that a receptor spends indoors and outdoors
while at home. It determines the fraction of time a receptor is exposed to external radiation with
shielding from the walls of the house. It also determines the fraction of time a receptor is exposed
to radon that accumulates within the home. The selected values are the reported averages for ages
18 to 64 reported in Table 16-22 of the 2011 Exposure Factor Handbook (U.S. EPA, 2011). The
remaining time not accounted for between these two fractions is assumed to be spent away from
home.
 Radon Emanation Coefficient is the fraction of the generated radon that escapes from the waste
matrix and is able to migrate into the surrounding air prior to decay. It determines the fraction of
radon that is released and is available to enter a home. Emanation rates were drawn from available
data for scale, sludge and contaminated media (API, 1990; Wilson and Scott, 1992; White and
Rood, 2000). The lower end of values reflects intact pipe scale, while the higher end of values
reflects disturbed scale and production sludge.
 Radium Ratio is the relative amount of 228Ra and 226Ra isotopes in the applied waste. This is not a
variable required by the RESRAD model. Instead, EPA used it along with the assumption to define
initial radium activities. EPA reviewed available data from the literature (Appendix B: Constituent
Database) to determine a range of radium ratios. Of those sources that reported activities for both
isotopes, the ratios for scale ranged between 0.01 to 2.5 with an average of 0.7, while reported
ratios for sludge ranged between 0.01 and 4.7 with an average of 0.5. Based on these data, EPA
selected ratios of 1:3 and 3:1 to provide a reasonable range.
 Application Area is the lateral extent over which the waste is spread. EPA selected 1-acre
(4,047 m2), based on the assumption that the residence is centrally located. It is anticipated that
waste application could cover an area considerably larger than a single acre. However, for the
purpose of this model, this area is sufficiently large approximate an infinitely wide source.
Increasing the area further will have negligible impacts on the calculated risk. For example, U.S.
DOE (1998) found that decreasing the area from 4 to 0.2 acres decreased exposures by only five
percent.
 Application Depth is the depth below ground surface that the waste is incorporated into the soil.
This mixing can dilute the activity of the waste and may contribute some additional shielding
from overlying soil. EPA considered two values for the thickness of the contaminated zone. The
first depth is 2 cm and represents surficial spreading without any active mixing. The second depth
is 20 cm that represents soil tilled with a standard disk tiller. Both values are based on the
recommended values in the Human Health Risk Assessment Protocol for Hazardous Waste
Combustion Facilities (U.S. EPA, 2005).
 Room Height is the vertical measurement of an average room in the residence. It determines the
volume of air in the house in which radon can accumulate. The selected value was drawn from
the U.S. Housing and Urban Development Residential Structural Design Guide (U.S. HUD, 2000).

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-11

 Room Area is the floor area of an average room in the residence. It determines the volume of air
in the house in which radon can accumulate. The selected value is the RESRAD default.
 Air Exchange Rate is the number of times that the total volume of air in a housing unit is
exchanged with outside air during a given time period. It determines the extent to which radon is
able to accumulate in the home before it is cycled out. The selected values are the national 10th
and 90th percentile values drawn from Table 19-24 of the 2011 Exposure Factors Handbook (US
EPA, 2011).
 Concrete Thickness is the distance that radon must migrate through the floor before it enters a
home. It determines the rate at which radon can accumulate in a home. The selected values were
drawn from the U.S. Housing and Urban Development Residential Structural Design Guide (U.S.
HUD, 2000).
 Concrete Density and Porosity are the compactness of the floor and the relative volume of void
spaces through which radon can travel. These variables determine the rate at which radon can
accumulate in a home. Values were drawn from Characterization of Radon Penetration of
Different Structures of Concrete (U.S. DOE, 1996).
 Shielding Factor is the fraction of the gamma ray energy that is absorbed by walls and other
obstacles located between the waste and receptor. The shielding factor is applied only when the
receptor is indoors. The lower value was drawn from Generic Procedures for Assessment and
Response During a Radiological Emergency (IAEA, 2000). The higher value is the RESRAD default
value. Denser materials, such as concrete and brick, offer higher shielding factors compared to
other building materials, such as wood.
EPA limited the scope of this analysis to a single scenario of a resident farmer living around the field
where the wastes had previously been applied. EPA only modeled exposures to external radiation and
radon because these were previously identified as the primary exposure pathways and there are greater
uncertainties associated with other type of releases (e.g., leachate). EPA modeled risks up to 1,000 years
following initial disposal of the waste with negligible losses to surface erosion or subsurface leaching.
Available data indicate the fraction of radium leached from these wastes is often minimal. Anoxic
conditions that may promote releases are not likely to form in the topsoil and any mass that is released
may sorb onto surrounding soil. Therefore, the assumption of negligible losses is considered appropriate
at this stage.
The model was run deterministically with each combination of the inputs listed in Table 7-4. The
model results are presented in Figure 7-1, plotted as a function of final soil activities ranging from 1 to
100 pCi/g. Given the radium activities measured in the various associated wastes, any of these soil
activities could result from surface disposal in the absence of relevant restrictions. Each line on the
graph reflects a different combination of inputs, with the top and bottom-most lines reflecting
combination of all high-end and low-end inputs, respectively.

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-12

Figure 7-1: RESRAD Model Results With and Without Radon Exposure
Potential risks from gamma radiation and radon greater than 1×10-5 are possible at every modeled soil
activity. However, the model results do not provide any information about which of these results are
most likely. It is possible that some of the modeled combinations are not realistic. For example, the
lower radon emanation factor is associated with intact scale. However, removal from the well and
mixing with the soil will inevitably disturb the integrity of scale, making higher emanation rates more
likely. The range of potential risks from gamma radiation alone (right) is narrower than for combined
gamma and radon (left). This is because many model inputs affect radon release and transport. Exposure
to gamma radiation is a more direct pathway. The lower bound on modeled risks in both graphs are
similar and attributed primarily to direct gamma exposure.
7.2.4. Findings
U.S. DOE (1998) found that soil activities greater than 5 pCi/g can result in exposures greater than the
dose limit of 100 mrem/yr recommended for the general public by the International Commission on
Radiological Protection. The results of this update to that analysis confirm that exposure to these
activities has the potential to result in doses that correspond to risks outside of the Office of Land and
Emergency Management risk range. However, this update does not provide a likelihood that such risks
will occur from current practices. Based on the activities measured in different E&P wastes (Section 5:
Waste Characterization), uncontrolled land application of E&P wastes have the potential to result in
soil activities at or above 5 pCi/g. However, it is not clear from available information which wastes are
currently land applied. Past reports reference application of drill cuttings, drilling fluid, produced water
and sludge. A number of states now have regulations in place that limit the activity in waste that can
be applied. Even if a higher activity wastes are applied, it is not possible to estimate the resulting soil
activity without more information on application rate and frequency. Therefore, there is not enough
1.E-06
1.E-05
1.E-04
1.E-03
1.E-02
1.E-01
1.E+00
1 10 100
Ri
s
k
Soil Activity (pCi/g)
Gamma and Radon
1.E-06
1.E-05
1.E-04
1.E-03
1.E-02
1.E-01
1.E+00
1 10 100
Soil Activity (pCi/g)
Gamma Only

Management of Oil and Gas Exploration, Development and Production Wastes
Section 7: Existing Evaluations 7-13

information available from this existing evaluation to draw conclusions about the current disposal
practices for E&P wastes.
Conclusions
The two identified evaluations indicate that adverse effects are possible from uncontrolled releases of
E&P waste. Similar risks have been previously documented in historical damage cases. However, the
majority of state regulatory programs now include specific requirements intended to prevent or
substantially mitigate these types of risk. For example, the majority of states currently require some
form of liner for pits that hold E&P waste and place limits on both where and how land application is
allowed. Therefore, these types of uncontrolled releases are less likely to occur. To better understand
the potential magnitude and frequency of environmental releases associated with current waste
management practices, EPA reviewed the available literature for documented damage cases.

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-1

8. Damage Cases
As part of the 1987 Report to Congress (RTC), EPA gathered information on instances where ongoing
management practices of E&P wastes had resulted in damage to human health and the environment.
The Agency found evidence at the time that damages could occur in instances where these wastes were
managed in accordance with applicable regulations. However, there have been considerable changes
to both the oil and gas industry and state regulatory programs over the last thirty years. To better
understand the effects of these changes, EPA conducted an updated review of recent damage cases that
occurred in state, federal or tribal jurisdictions. The following section details the approach used to
identify damages and the conclusions that can be drawn from the available information.
Review of Recent Damage Cases
EPA conducted a review of summary reports and other sources that had either been submitted to the
Agency or identified through an independent literature search. Based on this review, EPA identified
the following initial sources that had not previously been reviewed:
 Oil Field Produced Water Discharges into Wetlands in Wyoming (U.S. DOI, 2002);
 U.S. EPA Region 8 Oil and Gas Environmental Assessment Effort 1996-2002 (U.S. EPA, 2003);
 2016 Notice of Intent to Sue for Violation of Nondiscretionary Duties under the Resource
Conservation and Recovery Act with respect to Wastes Associated with the Exploration,
Development, or Production of Oil and Gas.
 Compendium of Scientific, Medical, and Media Findings Demonstrating Risks and Harms of
Fracking (Unconventional Gas and Oil Extraction) (CHPNY and PSR, 2018); and
 Individual news articles, scientific journals and state enforcement orders (Ramirez, 2010; Fehling,
2012; Vengosh et al., 2014; PADEP, 2014a,b; Flesher, 2015; ADSBRL, 2016; Fears, 2016; Lauer et
al. 2016; Schladen, 2016; AP, 2018; Geeza et al., 2018; Pappas, 2018).
The scope of damages considered in this review is broad and includes adverse health effects to humans
and wildlife, impairment of habitat, and degradation of natural resources. However, it is important to
note that this review only considered cases where a reasonably clear link of cause and effect exists
between the waste management practice and the resulting damages. Because this review relied on well-
documented cases by necessity, it is not expected to be exhaustive. For example, damage claims that
were settled outside of court are unlikely to be available in the public record. As a result, this review is
not intended to provide a statistically representative sample of the type or frequency of damages that
may occur. Instead, it aims to summarize the nature and extent of known damages and to highlight
specific management practices that might warrant further review.

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-2

8.1.1. Review Criteria
The Agency relied on a number of criteria to determine whether each of the reported incidents fell
within the scope of the current review. Incidents that did not meet all the criteria were not retained
for further consideration. EPA first applied the “tests of proof” used in the 1987 RTC to determine
whether a reported incident qualifies as a damage case (U.S. EPA, 1987a,b,c). An incident was retained
if there was sufficient information to classify it under one or more of the following categories:
 Scientific Investigation: Damages were found to exist as part of the findings of a scientific study.
Such studies could be extensive formal investigations supporting litigation or a state enforcement
action, or they could, in some instances, be the results of technical tests (such as monitoring of
wells) if such tests were a) conducted with state-approved quality control procedures and b)
revealed contamination levels in excess of an applicable state or federal standard or guideline.
 Administrative Ruling: Damages were found to exist through a formal administrative finding, such
as the conclusions of a site report by a field investigator, or through existence of an enforcement
action that cited specific health or environmental damages.
 Court Decision: Damages were found to exist through the ruling of a court or through an out-of-
court settlement.
EPA further focused the scope of the current review to incidents that occurred between 2012 and 2018.
During the most recent review of damage cases in 2010 (See: Section 2: Summary of Agency Actions),
EPA concluded that a number of incidents had occurred years before the state in question had
established relevant regulations and that enforcement of current regulations would prevent the vast
majority of identified incidents from reoccurring. Therefore, EPA excluded older incidents both
because of the timeframe of the previous review and the fact that older incidents are less likely to be
representative of current waste management practices. This is consistent with the Agency’s review in
the 1987 RTC that limited the review to the previous five years.
The damage cases assembled in the 1987 RTC were broad and often included incidents that extend
beyond the jurisdiction of RCRA. However, the scope of the current review is limited to whether
revisions to RCRA Subtitle D regulations are necessary to address ongoing risks from the management
of E&P wastes. Therefore, EPA focused the current review to include only management units that E&P
wastes currently exempt from regulation under RCRA Subtitle C. For example, the current review did
not address release incidents that result from disposal down injection wells. Nor did it address releases
of salable petroleum products, unused chemical feedstock, and other non-wastes.
EPA reviewed the release incidents reported in the identified sources based on the above criteria to
ensure that the damage cases are both reliable and relevant to the current review. When an incident
was judged not to be relevant, it was not retained for further review. When an incident was judged to
be relevant or potentially relevant, EPA assembled as much specific information as possible about the
location of the release, dates over which the release occurred, type and amount of waste released, the

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-3

contaminants of concern, type of management unit from which the waste was released, cause of the
release, whether the release occurred during operations allowed under state regulations, regulatory
response, and any criminal or civil penalties that resulted. However, many sources contain incomplete
documentation of the incidents. When insufficient information was available to determine the nature
of the release or the associated damages, EPA attempted to collect additional information from other
available sources, such as references cited in the initial source document, state websites, and broader
web searches. If the Agency was not able to find enough information to meet the test of proof, then
these incidents were not retained for further review.
8.1.2. Findings
Of the incidents reviewed, only eight met all the criteria and demonstrated a clear link between the
management of E&P wastes and the resulting damages. Table 8-1 provides a summary of the available
information for each of these incidents. A broader list of both the relevant and potentially relevant
incidents considered in this review are provided in Appendix A (Damage Cases).
Table 8-1. Summary of Relevant Damage Cases, 2012 – 2018
Location Release
Dates Waste Type Reported
COCs Unit Type Source Reported Damages
Kern County,
CA 1960 - 2018 Produced Water B, Cl
Evaporation
Pit, Spray
Irrigation
Seepage from
Disposal Unit,
Spray Irrigation
Contaminated GW
Pittsburgh,
PA 2011 - 2012 Produced
Wastewater Cl Pit Liner Leakage Contaminated GW & SW,
Impacted Vegetation
Chartiers, PA 2012 Frac Fluid,
Produced Water Cl, Mn Pit Liner Leakage Contaminated Soil
Hopewell,
PA 2013 Reuse Water Cl Pit Unspecified
Leak Contaminated Soil & GW
Amwell, PA 2013 - 2014 Frac Fluid,
Produced Water Cl Pit Pump Leak,
Liner Leakage Contaminated Soil
Mount
Pleasant, PA 2014 Frac Fluid,
Produced Water
Not
Reported Pit Unpermitted
Discharge
Soil Erosion, Deposition
to Sediment in SW Body
Yeager, PA 2014 Frac Fluids,
Produced Water TDS, Cl Pit Unspecified
Release Contaminated Soil & GW
Midway, TX 2016 Frac Fluid,
Produced Water
Not
Reported
Wastewater
Storage Tanks
Flooding, Tank
Failures Contaminated Soil & SW

Eight incidents involved management of produced water (e.g., wastewater, flowback fluid, brine, reuse
water) in pits and tanks. The magnitude of reported releases was highly variable, ranging in volume
from approximately 1,300 gallons to over 500,000 gallons. Few sources provided information on the
extent of contamination that resulted from these releases, but this may not have been known at the
time damages were first identified. Available information shows that corrective action efforts have

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-4

begun or been ordered to begin at each of these sites. In one case, a fine of $4.5 million was also levied
against the facility.
Each of the eight incidents resulted in contamination of one or more environmental medium (i.e., soil,
groundwater, surface water, sediment). Most damages were identified from measured concentrations,
though few sources indicated what contaminant levels were present or what benchmarks were used
for comparison. All of the reported contaminants are inorganic elements commonly found in produced
water at elevated concentrations (Section 5: Waste Characterization). The most common contaminant
was chloride. It is unclear if the contaminants reported served as an initial basis to identify damages or
if the list reflects the full extent of contamination considered. There is potential for a number of other
inorganic elements and organic compounds to be present in produced water and other E&P wastes, so
partial characterization of the spill might result in incomplete remedial efforts.
Four of the identified incidents were associated with units that were not in compliance with existing
laws or regulations. For example, one incident (Pittsburgh, PA) involved the management of produced
water in a pit that was only permitted to store fresh water. Another incident (Hopewell, PA) involved
a pit that did not install the groundwater monitoring wells required by permit and so failed to identify
subsurface leaks in a timely manner. A majority of the remaining incidents were a result of faulty or
degraded equipment (e.g., poorly installed liners, tank collapse, leaks from pumps).
It is noteworthy that a majority of the identified incidents occurred in Pennsylvania. However, it is
highly unlikely that the actual frequency of releases is so disproportionately high in Pennsylvania
compared to other states. Instead, given the high level of scrutiny that has been applied to the state in
recent years due to increased concerns about drilling in the Marcellus shale, it is more likely to be a
result of better documentation and communication with the public. Thus, the lack of damage cases
identified in other states does not necessarily mean that none have occurred, nor does it mean that
other states have not taken appropriate steps to address the environmental impacts from releases.
However, the lack of available data for other states make it difficult to draw conclusions about the
representativeness of the identified damage cases.
Spill Reporting
During the search of state websites associated with E&P waste regulatory programs, EPA identified
four states that maintain centralized databases of spills that occur during site activities (i.e., Colorado,
New Mexico, North Dakota, Wyoming). Although several other states collect information on spills, the
data are extremely difficult to aggregate because specific information, such as the facility location
(latitude and longitude) or the facility name is required to search the data (e.g., Oklahoma,
Pennsylvania, Texas, West Virginia). The effort needed to assemble and review data for these additional
states was prohibitive at this time. Regulations in these states require that spills above a set volumetric
threshold be reported to the state within a certain timeframe. Identification and cleanup of the spills is
conducted in accordance with state requirements for corrective action and so sites are typically not

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-5

subjected to fines in response. Because the releases are generally contained and addressed onsite
without the need for enforcement action,22 these spills were not classified as damage cases. EPA
reviewed the spill databases from the four states to identify data related to spills of E&P waste from
waste management units (e.g., pits, tanks). Table 8-4 provides a summary of the available data over a
3-year period between 2014 and 2017.
Table 8-2. Summary of Reported Spills for Select States, 2014 – 2017
State Unit
Type
Number
of Active
Units
Number of
Reported
Releases
Number
Reported
with
Volume
Total
Reported
Volume
(BBLs)
Average
Reported
Volume
(BBLs)
Most Frequent
Spill Causes
Colorado
Pits 3,417 51 17 21,159 1,245
Not Reported (31),
Equipment Failure (12),
Human Error (8)
Tanks 1,441 529 206 14,150 69
Equipment Failure (251),
Not Reported (235),
Human Error (34)
Central
Disposal 41 11 10 1,290 129
Human Error (6),
Equipment Failure (4),
Not Reported (1)
New
Mexico
Pits NR 5 5 127 25 Not Reported (5)
Tanks NR 516 433 82,262 190
Not Reported (197),
Equipment Failure (169),
Human Error (24)
Wyoming Total NR 408 407 203,566 500 Equipment Failure (349),
Human Error (38)
NR – Not Reported
Colorado: http://cogcc.state.co.us/cogis/IncidentSearch.asp
New Mexico: https://wwwapps.emnrd.state.nm.us/ocd/ocdpermitting//Data/Incidents/Spills.aspx
Wyoming: http://deq.wyoming.gov/admin/spills-and-emergency-response/

A similar number of total spills were identified across several states, though the typical volume released
varied more widely. The most common waste reported by each state was produced water, which is also
the largest volume waste generated during well production. Other wastes include drilling mud and
tank bottoms. The reported spills can be generally categorized as resulting from equipment failure
(e.g., damaged liner, breached berm, corrosion), weather events (e.g., flooding, lightning), and human
error (e.g., overfilling). However, root causes do not always fall into neat categories, as equipment
failure may sometimes be a form of human error due to poor maintenance or lack of planning. Nearly
half of the incidents had no reported cause. The types of spills identified in this review align well with
the findings of previous reviews of spills in other regions of the country (U.S. EPA, 2015b; 2016a).

22) For example, it has been reported that around 80% of spills in North Dakota are contained onsite (King and Soraghan, 2015).

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-6

Although the reported spills were identified between 2014 and 2017, that does not mean all of the spills
originated during this timeframe. Some of the “historic” spills occurred at some earlier time, but were
only identified during decommissioning of a tank battery, replacement of subgrade equipment, or other
routine facility maintenance. Subsurface releases are more difficult to identify and this may explain the
greater number of spills recorded for tanks. While groundwater monitoring may help to eventually
detect leaks, contamination may not reach the installed wells before the unit is taken out of service for
repair or decommissioned.
Only one state, Colorado, provided information on how corrective action is implemented at spill sites.
Colorado requires that the extent of soil and groundwater contamination be identified by sampling of
soil and groundwater assisted with photoionization detector and the installation of temporary
groundwater monitoring wells. Chemical analyses are generally limited to TPH, BTEX and select
inorganics. Soil remediation typically involves excavation of the contaminated soil and/or in-situ
treatment (e.g., stabilization). Groundwater remediation typically involves in-situ treatment
(e.g., chemical oxidation, bioremediation), natural attenuation, and/or pumping groundwater to an
offsite treatment facility. Sites are required to sample groundwater quarterly until relevant maximum
contaminant levels are achieved. Of the 149 spills found to have reached groundwater between 2014
and 2017, 142 (95.3%) were considered resolved as of late-2017.
State Inspection and Enforcement
EPA searched the websites of thirty-five states for information on releases of E&P waste. During this
search, EPA identified three states that published summary reports on the number of inspections and
resulting enforcement actions taken on a yearly basis. These actions included both informal notices of
the violation and formal enforcement orders. EPA did not include these violations in the list of damage
cases because a number of violations identified did not involve actual releases to the environment.
Rather, these other violations involved non-compliance with specific state requirements, such as failure
to adequately label tanks or remove equipment from around inactive wells. Enforcement of these
requirements helps prevent minor infractions from potentially becoming major releases. The violations
that did result in releases are a clear result of non-compliance with state regulations, though there was
not enough information available to define the type of waste involved, the cause of the release, or the
resulting damages. Therefore, it is difficult to aggregate individual violations in a meaningful way.
However, these reports still provide information that can be used to better understand the structure
and implementation of state programs. Table 8-2 provides a summary of the available information for
these three states. The number of inspectors was from state websites. EPA did not include supervisors
or support staff (e.g., quality assurance officer) in the list of inspectors.

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-7

Table 8-3. Summary of State Inspections and Enforcement Actions in 2018
State Source Number of
Inspectors
Number of
Inspections
Number of
Violations
Penalties
Assessed
Colorado CODNR (2019) 20 Not Reported 163 $9,832,096
Pennsylvania PADEP (2018) 100* 35,556 2,290 $9,590,432
Texas TXRRC (2018) 158 130,064 29,964 $5,718,143
* Most recent data available from IPAA (2013).
Colorado Inspectors: https://cogcc.state.co.us/about.html#/staffmaps
Texas Inspectors: https://www.eenews.net/energywire/2017/02/09/stories/1060049755

State inspectors work to ensure compliance with applicable state regulations at both drilling sites and
centralized waste disposal operations. Therefore, the number of inspectors and enforcement personnel
employed by states is a useful metric that can be compared with different measures of enforcement
(e.g., number of inspections) or production (e.g., number of wells) to better understand how the state
programs are currently implemented. A greater number of inspectors relative to the number of facilities
that require inspection is generally considered desirable because it would allow more regular inspection
of individual sites. Infrequent inspections may allow violations to go unnoticed, particularly in remote
or unpopulated areas, which may eventually result in environmental releases.
Data for these states indicate that in 2016 each inspector visited an average of 356 wells in Pennsylvania
and 781 wells in Texas. Data on the number of inspections was not identified for Colorado; however,
the state reported that each inspector visited an average of 1,000 wells in 2015 (COOGTF, 2015). At
these rates, it would take between 2.2 and 2.7 years to visit every well in these states, though it is
unlikely each of the wells would be visited with the same frequency. States can and do place greater
emphasis on inspections of certain operations. The Colorado Department of Natural Resources reports
the use of a risk-based strategy to prioritize inspection of the phases of E&P operations considered most
likely to experience violations (CODNR, 2014). A study conducted with data from the Pennsylvania
Department of Environmental Protection found that the average time between inspections in this state
increased from 0.3 years for newly installed wells to 2.8 years for those in operation for nearly a decade
(Ingraffea et al., 2014). This compares well with the calculated average of 2.2 years for all wells.
There is, however, no apparent correlation between the number of inspections conducted and the
number of violations identified across the different states. States with fewer reported violations tended
to levy higher individual fines. Larger fines may be used as a deterrent to compensate for fewer staff or
less frequent inspections. However, it is not clear how states keep track of violations. The total number
reported might capture each individual violation identified or only the sites where violations occurred.
Therefore, it is difficult to draw meaningful comparisons among the states.
As part of the 1987 RTC, EPA compared the number of inspectors and enforcement personnel in 12
states with the number of active oil and gas wells in the states. EPA updated this comparison for 11 of
the same states based on the most recent data available. Data were not identified for Kansas and so it is
not included in the current comparison. Table 8-3 provides estimates of the number of inspectors

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-8

employed relative to the number of active wells in each state. Recent estimates align well with the
estimates for western states made in 2015 (COOGTF, 2015).
Table 8-4. Summary of Inspection and Enforcement Personnel in Selected States, 1987 - 2018

State
1984-1986 2017-2018 Change to
Wells per
Inspector
Active
Wells
Number of
Inspectors
Wells per
Inspector
Active
Wells
Number of
Inspectors
Wells per
Inspector
Alaska 1,295 16 81 2,421 5 484 ↑ 498%
Arkansas 11,982 9 1,331 11,563 3 3,854 ↑ 190%
California 56,645 31 1,827 50,874 40* 1,271 ↓ 30%
Louisiana 40,259 68 592 35,839 31 1,156 ↑ 95%
New Mexico 40,294 10 4,029 57,868 18 3,215 ↓ 20%
Ohio 60,553 66 917 42,059 36 1,168 ↑ 27%
Oklahoma 122,667 52 2,359 81,822 50 1,636 ↓ 31%
Pennsylvania 44,789 34 1,317 78,842 100* 788 ↓ 40%
Texas 278,811 120 2,323 305,895 158 1,936 ↓ 17%
West Virginia 48,395 15 3,226 55,912 18 3,106 ↓ 4%
Wyoming 14,438 12 1,255 33,366 11 3,033 ↑ 142%
* Most recent data available from IPAA (2013).
Alaska Inspectors: http://doa.alaska.gov/ogc/reports/reportsAndStudies/AOGCC_Statement_to_Gov.pdf
Arkansas Inspectors: http://www.aogc.state.ar.us/about/staff.aspx
Louisiana Inspectors: http://www.dnr.louisiana.gov/index.cfm/page/558#Engineering-Regulatory-Division-Direct
New Mexico Inspectors: http://www.emnrd.state.nm.us/OCD/about.html
Ohio Inspectors: http://oilandgas.ohiodnr.gov/inspectors
Oklahoma Inspectors: http://www.occeweb.com/contactlist/ogcontacts.htm
West Virginia Inspectors: https://apps.dep.wv.gov/oog/contact_new.cfm
Wyoming Inspectors: http://wogcc.wyo.gov/home/contacts

EPA noted in the 1987 RTC that enforcement of regulations was made more difficult in some regions
of the country by the limited availability of state inspection and enforcement personnel. However,
multiple states have decreased the number of inspectors over the past three decades. States that
increased the number of inspectors are often those that have seen recent increases in production from
tight oil and shale gas reservoirs. The magnitude of change in the well-inspector ratio ranges between
a 40% decrease to a nearly 500% increase. Although the percent change is useful to track trends within
a state, it does not provide a meaningful comparison between states as the state with the greatest
increase (i.e., Alaska) still maintains the lowest overall ratio. In addition, statistics based on number of
active wells may not adequately reflect the waste management units and other equipment associated
with the wells that must also be inspected. There can be multiple pits and tanks present at a single
drilling site. There can also be pits, tanks, and other management units (e.g., land application) at offsite
disposal locations. Yet, as discussed in Section 4 (Waste Management), information available on the
total number and location of such units in each state is limited.
Based on inspection rates previously estimated for Colorado, Pennsylvania and Texas, it could take the
remaining nine states anywhere from 0.3 to 10.8 years to cover all of the active wells with the current

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-9

number of inspectors. It is not apparent whether an ideal ratio of wells (or other metric) to inspectors
exists. The same number of wells may need greater or fewer inspectors in different states based on a
number of regional factors, such as the average distance between wells and the use of other methods
to limit violations (e.g., spill reporting requirements, groundwater monitoring, higher fines).
The frequency of inspections is an important consideration, but how inspectors interpret and enforce
the state regulations are also important considerations. Therefore, it is critical that the inspectors are
adequately trained to ensure both an understanding of the issues that may be encountered around E&P
sites and consistent identification of and response to violations. This may accomplished through
development of training standards, inspector certification programs or other technical assistance
efforts. Some states have standardized training programs in place and some have taken public steps in
recent years to invest additional resources. West Virginia developed a standardized observation
checklist and an operations and maintenance questionnaire for the inspection of pits and tanks to
ensure the field observations were recorded in a consistent method in response to a study in 2013
commissioned by the state legislature (WVDEP, 2013). In 2016, California awarded a contract to
TOPCORP, an educational consortium composed of the Colorado School of Mines, Pennsylvania State
University and University of Texas at Austin, to train inspectors through a combination of online
training, classroom instruction and field experience.
Conclusions
EPA reviewed the release incidents that had been submitted to the Agency, as well as additional
incidents identified during this review, to understand the type and frequency of releases from waste
management units containing E&P wastes. Altogether, this review identified eight confirmed damage
cases. During the damage case review, EPA also identified several state databases that provide
information on the number of violations identified during inspections or reported spills. The databases
include thousands of additional incidents; however, these incidents were not counted as damage cases
because there was no evidence provided of adverse effects. Reported violations did not always involve
releases to the environment. A number involved non-compliance with specific state requirements, such
as failure to adequately label tanks or remove equipment from around inactive wells. Reported spills
did involve releases to the environment; however, these releases were often limited by secondary
containment and were addressed upon discovery without the need for state enforcement action. The
conclusions that can be drawn from available data on violations and spills are more limited because
these datasets primarily represent instances where the existing regulations were successfully enforced.
However, the types of releases observed from spills align well with findings identified in both in this
current review for damage cases and a previous reviews of spills conducted by the Agency (U.S. EPA,
2015b; 2016a).
EPA studied the available data to determine whether patterns exist in the type and frequency of
releases. It does not appear that any one type of waste management unit is more likely to result in
releases; however, little information was identified for some types of waste management units

Management of Exploration, Development and Production Wastes
Section 8: Damage Cases 8-10

(e.g., land application). The available data indicated that a greater proportion of the identified damage
cases involved pits and a greater proportion of reported spills involved tanks. It is possible that releases
to the subsurface from pits and buried equipment make it more difficult to identify releases from
equipment failure. However, routine maintenance and inspections during the operational life of the
unit, as well as requirements to survey the area when a unit is taken out of service for periodic cleaning
or repair can help to ensure that releases are identified and remediated.
EPA found no indication that the types of uncontrolled releases from waste management units
identified in historical damage cases are common. The two main causes of releases identified from E&P
operations are now equipment failure (e.g., corrosion) and human error (e.g., overfilling tanks). These
types of releases can be mitigated within the framework of existing state programs through increased
enforcement of existing state regulations. However, some states appear to have reduced the number of
inspectors relative to the number of active wells over the past three decades. This indicates that there
is an opportunity to improve compliance through greater resources toward enforcement.

Management of Exploration, Development and Production Wastes
Section 9: Summary and Conclusions 9-1

9. Summary and Conclusions
In 1988, EPA issued a regulatory determination that exempted wastes associated with the exploration,
development and production (E&P) of crude oil, natural gas and geothermal energy from Subtitle C of
RCRA (53 FR 25446). Over the last three decades, there have been significant advancements in the
production of crude oil and natural gas from hydraulic fracturing and directional drilling used to access
black shale, tight oil and other “unconventional” formations. This document reviews the information
currently available to the Agency about the generation, management and ultimate disposal of E&P
wastes, assesses the likelihood of adverse effects to human health or the environment from current
practices and presents EPA’s determination of whether revisions to federal regulations are necessary to
address the identified risks. This review focused primarily on E&P wastes from crude oil and natural
gas, as available data indicate that geothermal production remains limited to a few states and has not
undergone a similar surge in production. This section summarizes the findings of EPA’s review and
documents the Agency’s rationale for why revisions to regulations for E&P waste management are not
necessary at this time, based on the currently available information.
In the 1988 Regulatory Determination, EPA laid out a multi-pronged strategy to identify and address
issues posed by the management of E&P wastes, that included working to improve state programs as
well as addressing gaps in federal Subtitle D regulations. The Agency has since taken a number of steps
to improve existing waste management programs by supporting independent reviews of state programs
(e.g., State Review of Oil and Natural Gas Environmental Regulations) and compiling existing guidance
and information on best management practices (e.g., U.S. EPA, 2014b). These efforts have resulted in
substantive changes to state regulations for pits, tanks, offsite disposal, centralized facilities, spill
reporting, corrective action, remedial standards, and other areas. EPA has also undertaken a number of
important efforts and actions related to E&P operations under other Agency programs, such as a study
of the potential impacts of hydraulic fracturing on drinking water resources (U.S. EPA, 2016a) and new
regulations that address effluent limitation guidelines and pretreatment standards for oil and gas
operations (44 FR 22069, 58 FR 12454, 61 FR 66086, 66 FR 6849, 81 FR 41845).
In 2016, EPA was sued for its alleged failure to review and, as necessary, revise its federal non-
hazardous solid waste regulations for E&P wastes. This lawsuit was based on section 2002(b) of RCRA,
which requires every regulation promulgated under the Act to be reviewed and, where necessary,
revised not less frequently than every three years. In response to the lawsuit, EPA entered into a
consent decree to conduct the review and formally document whether revisions are necessary at this
time. To support this effort, EPA conducted an extensive literature review of government, industry and
academic sources to supplement the information available from previous Agency actions. EPA also
conducted a review of available information on factors such as management practices, waste

Management of Exploration, Development and Production Wastes
Section 9: Summary and Conclusions 9-2

characteristics, state programs and damage cases in order to determine whether changes to the federal
solid waste regulations are necessary.
In sum, the combined use of hydraulic fracturing and directional drilling has altered the energy
production landscape in the United States. Production in some states, such as North Dakota and
Pennsylvania, has increased by nearly an order of magnitude in the past decade. As of 2017, horizontal
wells accounted for nearly 13% of active wells in the United States (U.S. DOE, 2018e). Although the
number of newly installed wells has declined sharply in recent years, production has continued to
increase as a result of higher production rates from the horizontal wells (IPAA, 2017; U.S. DOE,
2018c,d). Increased production has the potential to generate greater volumes of waste. Some states
collect and maintain data on the volumes of E&P wastes generated within their respective borders, but
the methods and metrics used to collect these data are not uniform and so waste volumes reported at a
national scale are only estimates. It is clear from available data that produced water accounts for the
vast majority of the wastes generated, followed distantly by wastewater treatment residuals, spent
drilling fluid and drill cuttings (API, 2000). A number of other waste liquids and solids are generated
at far lower volumes and may be comingled in the same pits and tanks as higher-volume wastes prior
to disposal.
Available data indicate that a considerable fraction of both liquids and saturated solids are disposed
through injection into deep formations; however, this disposal method falls outside the scope of the
RCRA Subtitle D regulations in 40 CFR Part 257. There are a number of other options available for
both onsite or offsite management of the remaining wastes, depending on the local infrastructure and
state regulatory requirements. States with higher oil and gas production are more likely to have
centralized or commercial facilities designated specifically for the treatment and disposal of E&P
wastes. States with lower production are more likely to utilize existing infrastructure for non-
hazardous wastes. However, the way that wastes are ultimately managed is primarily a decision made
by industry within the bounds of applicable state and federal regulations.
Both hydraulic fracturing and directional drilling have the potential to impact the composition of E&P
wastes. EPA reviewed publicly available data on the composition and behavior of these wastes. This
review shows that there can be orders-of-magnitude variability in the composition of each waste type,
though trends are apparent for certain constituents that might be used to predict where elevated levels
are more likely to occur. Some inorganic elements (e.g., lithium, molybdenum), organic compounds
(e.g., benzene) and radioisotopes (e.g., radium) appear to be correlated with either the organic carbon
content of the source rock or the salinity of the formation water. Horizontal wells are frequently drilled
a greater distance through organic-rich rocks with saline formation water, and therefore higher
constituent levels may be more common in the wastes from these wells, but similar orders-of-
magnitude levels can be possible in the wastes from vertical wells. Therefore, it is likely that similar
regulatory controls would be appropriate for the wastes from both types of wells. However, waste
composition is not static. Wastes may be intermingled during storage or treated in preparation for

Management of Exploration, Development and Production Wastes
Section 9: Summary and Conclusions 9-3

disposal, which may result in dilution or concentration of constituent levels. Therefore, it is important
to understand the waste composition and behavior at the time of disposal to determine whether the
wastes are being managed appropriately.
EPA reviewed state regulations for E&P wastes to determine the scope of coverage (e.g., the wastes and
activities), and the level of detail and precision in the requirements. This analysis provided an
understanding of state programs and whether each program includes elements that are part of
comprehensive waste management programs (e.g., waste containment, monitoring, unit closure), and
that would likely be elements of a revised federal solid waste regulation were that deemed to be
necessary. EPA reviewed 28 of the 34 states with reported oil and gas production, which together
account for over 99% of oil and gas production in the United States. The result of this review shows
that states are actively engaged in addressing the challenges posed by increased E&P operations, and
have been responding in part by updating their waste management programs. A total of 24 states, which
account for approximately 95% of national production, have updated their regulations applicable to
E&P wastes since 2013. The scope and specificity of regulatory programs varies among the states, based
on multiple factors such as the quantity of oil and gas produced in the state and the prevalence of
hydraulically fractured wells. Despite this variability, EPA found that states incorporate many of the
regulatory elements that are important components of waste management programs, such as requiring
liners for pits, secondary containment and groundwater monitoring. This provides confidence that the
scope of current state programs is robust. However, the way that regulations are interpreted and
implemented is also important considerations.
To better understand which practices may pose concern, EPA also reviewed the assembled literature
for existing evaluations that had drawn conclusions about the potential for adverse effects from
management of E&P wastes. Two existing evaluations identified potential adverse effects associated
with uncontrolled releases from pits and land application. EPA reviewed both to determine whether
the data and analyses that underpin these findings are of sufficient quality to support conclusions about
the current management of E&P wastes. Based on this review, EPA concluded that the identified risks
are possible when no controls are in place, as has been previously documented in historical damage
cases. However, many state programs now include specific requirements that address issues, such as
liners for pits, limits on land application, and other standards that address the risks associated with
historical damage cases. Therefore, EPA also reviewed available data on recent environmental releases
to better understand the current performance of state programs.
EPA reviewed the release incidents that had been submitted to the Agency, as well as additional
incidents identified during this review, to understand the type and frequency of releases from E&P
waste management units. EPA considered releases from these units that resulted in documented
adverse health impacts to humans and wildlife, impairment of habitat or degradation of natural
resources. EPA further focused this review to releases that had occurred or were ongoing in the past
six years to best reflect current management practices. Applying these criteria, this review identified
eight damage cases. During the review of damage cases, EPA also identified several state databases that

Management of Exploration, Development and Production Wastes
Section 9: Summary and Conclusions 9-4

provided information on the number of violations identified during inspections and reported spills.
The databases include thousands of additional incidents; however, these releases were not counted as
damage cases because there was no evidence available of adverse effects. Reported violations did not
always involve releases to the environment. A number involved non-compliance with specific state
requirements, such as failure to adequately label tanks or to remove equipment from around inactive
wells. Reported spills did involve releases to the environment; however, these releases were often
limited by secondary containment and were addressed upon discovery without the need for state
enforcement action. EPA reviewed the available data to determine whether patterns exist in the type
and frequency of releases and found no indication that the types of uncontrolled releases identified in
historical damage cases are common. Instead, human error (e.g., overfilling tanks) and equipment
failure (e.g., liners damaged during solids removal) are the two main causes identified from the available
data. These types of releases can be appropriately and more readily addressed within the framework of
existing state programs through increased inspections, improved enforcement and other targeted
actions than through the imposition of addition requirements under subtitle D of RCRA.
Based on the information gathered for this review, EPA concludes that revisions to the federal
regulations for the management of E&P wastes under Subtitle D of RCRA (40 CFR Part 257) are not
necessary at this time. The oil and gas industry has undergone a significant transformation in recent
years from the use of directional drilling and hydraulic fracturing to access unconventional formations,
but states have also revised their regulatory programs to adapt to the challenges posed by these
technological advancements; some within the last year. While higher constituent levels may occur
more frequently in wastes from newer horizontal wells, similarly high levels are also possible in wastes
from vertical wells. Therefore, it is likely that similar regulatory controls are appropriate for the wastes
from both types of wells. Based on EPA’s review, current state programs incorporate the majority of
elements that are important components of waste management programs, which indicates that the
scope of existing regulatory programs is robust. There is considerable diversity in how these elements
are incorporated in the different state programs, and so how the programs are implemented is also an
important consideration. EPA therefore also examined the implementation of state programs based on
the frequency, magnitude and extent of recorded releases. Historical damage cases and evaluations have
shown that adverse effects can result from uncontrolled releases of E&P wastes. However, there is
currently no evidence that these types of releases are common, as majority of the recently identified
releases were well-contained and addressed onsite. The primary causes identified for these releases
were human error and non-compliance with existing state regulations. The available information does
not indicate that new federal solid waste regulations would prevent or substantially mitigate these types
of releases. Instead, human error and non-compliance can be appropriately and more readily addressed
within the framework of existing state programs through increased inspections, improved enforcement
and other targeted actions. EPA will continue to work with states and other organizations to identify

Management of Exploration, Development and Production Wastes
Section 9: Summary and Conclusions 9-5

areas for continued improvement and to address emerging issues to ensure that E&P wastes continue
to be managed in a manner that is protective of human health and the environment.23

23) EPA signed a memorandum of understanding with STRONGER on November 19, 2018 to collaborate and improve both
environmental protections and economic outcomes through enhanced enforcement and compliance efforts for E&P waste
management.

Management of Exploration, Development and Production Wastes
Section 10: References 10-1

10. References
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Water.” Environmental Engineering Science. 32(9):514-524.
ADSBRL (Advanced Disposal Services Blue Ridge Landfill). 2017. “Corrective Action Plan (CAP) for
the Blue Ridge Landfill, Estill County, Kentucky.” Prepared by Gradient. Irvine, KY. May.
AKDEC (Alaska Department of Environmental Conservation). 1994. “Pollution Prevention
Opportunities for the Oil Field Service Industry.” Prepared by the ADEC Pollution Prevention
Office. Anchorage, AK.
AP (Associated Press). 2018. “Produced Water Spill Impacts Farmland in Mountrail County.” U.S. News
& World Report. Published online by the U.S. News & World Report L.P. on 9/18/18.
API (American Petroleum Institute). 1987. “Oil and Gas Industry Exploration and Production Wastes.”
Document No. 471-01-09. July.
API. 1989. “A National Survey on Naturally Occurring Radioactive Materials (NORM) in Petroleum
Producing and Gas Processing Facilities.” Prepared by G.H. Otto of the University of Houston for
API. July.
API. 1990. “Management and Disposal Alternative for NORM Wastes in Oil Production and Gas Plant
Equipment.” RAE-8837/2-2. Prepared by R.D. Baird, G.B. Merrell, R.B. Klein, V.C. Rogers and K.K.
Nielson of Rogers and Associated Engineering Corporation for API. May.
API. 2000. “Overview of Exploration and Production Waste Volumes and Waste Management Practices
in the United States.” Prepared by ICF Consulting for API. May.
Arthur, M.A. and B.B. Sageman. 1994. “Marine Black Shales: Depositional Mechanisms and
Environments of Ancient Deposits.” Annual Review of Earth and Planetary Sciences. 22(1):499-
551.
ASTSWMO (Association of State and Territorial Solid Waste Management Officials). 2015. “Oil and
Gas Exploration and Production Waste Management Survey Report.” Washington, DC. March.
ATSDR (Agency for Toxic Substances and Disease Registry). 1990. “Toxicological Profile for Radium.”
Atlanta, GA: U.S. Department of Health and Human Services, Public Health Service. December.
ATSDR. 2007. “Toxicological Profile for Barium.” Atlanta, GA: U.S. Department of Health and Human
Services, Public Health Service. August.

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Balashov, V.N., W. Engelder, X. Gu, M.S. Fantle and S.L. Brantley. 2015. “A Model Describing
Flowback Chemistry Changes with Time after Marcellus Shale Hydraulic Fracturing.” American
Association of Petroleum Geologists Bulletin. 99(1):143-154.
Bernhardt, D.E., D.H. Owen and V.C. Rogers. 1996. “Assessments of NORM in Pipe from Oil and Gas
Production.” NORM/NARM: Regulation and Risk Assessment, Proceedings of the 29th Midyear
Topical Meeting of the Health Physics Society, Scottsdale, AZ, January 7-10.
Blauch, M.E., R.R. Meyers, T.R. Moore, B.A. Lipinski and N.A. Houston. 2009. “Marcellus Shale Post-
Frac Flowback Waters – Where is All the Salt Coming From and What are the Implications?”
Society of Petroleum Engineers Eastern Regional Meeting, Charleston, WV, September 23-25.
Brumsack, H.J. 2005. “The Trace Metal Content of Recent Organic Carbon-rich Sediments:
Implications for Cretaceous Black Shale Formation.” Palaeogeography, Palaeoclimatology,
Palaeoecology. 232:343-361.
Candler, J.E., A.J.J Leuterman, S.Y.L Wong, and M.P. Stephens. 1992. “Sources of Mercury and
Cadmium in Offshore Drilling Discharges.” Society of Petroleum Engineering. 7(4):279-283.
CADHS/DC (California Department of Health Services and Department of Conservation). 1996. “A
Study of NORM Associated with Oil and Gas Production Operations in California. Sacramento,
CA.”
Carpenter, C. 2014. “Centralized Water-Management Facilities in the Piceance Basin.” Journal of
Petroleum Technology. 66(12):126-129.
CHDT (Clean Harbors Deer Trail). 2015. “Alternate Analysis Technique for Radium-226 to Assure
Compliance with Disposal Criteria at Clean Harbors Deer Trail Facility.” Prepared by J.M. Langsted
of Chicago Bridge & Iron Company. March.
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U.S. DOE. 2009. “Produced Water Volumes and Management Practices in the United States.”
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in 2015.” Prepared by the Energy Information Administration. Washington, DC. July.
U.S. DOE. 2018a. “The Distribution of U.S. Oil and Natural Gas Wells by Production Rate.” Prepared
by the Energy Information Administration. Washington, DC. October.

Management of Exploration, Development and Production Wastes
Section 10: References 10-13

U.S. DOE. 2018b. “Number of Producing Gas Wells” [Spreadsheet]. Prepared by the Energy
Information Administration. Washington, DC. November.
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U.S. DOE. 2018d. “Natural Gas Gross Withdrawals and Production” [Spreadsheet]. Prepared by the
Energy Information Administration. Washington, DC. November.
U.S. DOE. 2018e. “Today in Energy: U.S. Crude Oil and Natural Gas Production Increased in 2017, with
Fewer Wells.” Prepared by the Energy Information Administration. Washington, DC. November.
U.S. DOE. 2018f. “Today in Energy: Permian Region is Expected to Drive U.S. Crude Oil Production
Growth through 2019.” Prepared by the Energy Information Administration. Washington, DC.
August.
U.S. DOE. 2019. “Annual Energy Outlook 2019.” Prepared by the Energy Information Administration.
Washington, DC. January.
U.S. DOI (United States Department of the Interior). 1911. “The Data of Geochemistry: Second
Edition.” Bulletin 491. Prepared by the United States Geological Survey. Washington, DC.
U.S. DOI. 1958. “Barite Resources in the United States.” Geological Survey Bulletin 1072-B. Prepared
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U.S. DOI. 1961. “Geology and Geochemistry of Uranium in Marine Black Shales: A Review.
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U.S. DOI. 1993. “Contaminants in Oil Field Produced Waters Discharged into the Loch Katrine
Wetland Complex, Park County, Wyoming and their Bioconcentration in the Aquatic Bird Food
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Wyoming. December.
U.S. DOI. 1997a. Effects of Produced Waters at Oilfield Production Sites on the Osage Indian
Reservation, Northeastern Oklahoma. Open File Report 97-28. Prepared by the United States
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U.S. DOI. 2002. “Oil Field Produced Water Discharges into Wetlands in Wyoming.” Contaminant
Report Number: R6/718C/02. Prepared by the United States Fish and Wildlife Service. Cheyenne,
WY. January.

Management of Exploration, Development and Production Wastes
Section 10: References 10-14

U.S. DOI. 2009. “Reserve Pit Management: Risk to Migratory Birds.” Prepared by the United States
Fish and Wildlife Service. Cheyenne, WY. September.
U.S. DOI. 2011. “Oil and Gas Produced Water Management and Beneficial Use in the Western United
States.” Science and Technology Program Report No. 157. Prepared by the Bureau of Reclamation.
Denver, CO. September.
U.S. DOI. 2013a. “Produced Water Reuse Case Studies” [Power Point]. Prepared by K. Dahm and K.
Guerra of the Bureau of Reclamation. Presented at the EUCI: Produced Water Management in the
West Conference on May 21.
U.S. DOI. 2013b. “Geochemical and Mineralogical Data for Soils of the Conterminous United States:
USGS Data Series 801.” Prepared by the United States Geological Survey. Reston, VA.
U.S. DOI. 2016. “U.S. Geological Survey National Produced Waters Geochemical Database v2.2.”
[Database]. Prepared by M.S. Blondes, K.D. Gans, M.A. Engle, Y.K. Kharaka, M.E. Reidy, V.
Saraswathula, J.J. Thordsen, E.L. Rowan and E.A. Morrissey of the United States Geological
Survey. Published online on 02/16/16.
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Production of Crude Oil, Natural Gas, and Geothermal Energy. Volume 1 of 3: Oil and Gas.”
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Washington, DC. December.
U.S. EPA. 1987b. “Report to Congress: Management of Wastes from the Exploration, Development,
and Production of Crude Oil, Natural Gas, and Geothermal Energy. Volume 2 of 3: Geothermal
Energy.” EPN530-SW-88-003. Prepared by the EPA Office of Solid Waste and Emergency
Response. Washington, DC. December.

Management of Exploration, Development and Production Wastes
Section 10: References 10-15

U.S. EPA. 1987c. “Report to Congress: Management of Wastes from the Exploration, Development, and
Production of Crude Oil, Natural Gas, and Geothermal Energy. Volume 3 of 3: Appendices.”
EPN530-SW-88-003. Prepared by the EPA Office of Solid Waste and Emergency Response.
Washington, DC. December.
U.S. EPA. 1987d. “Onshore Oil and Gas Exploration, Development and Production: Human Health and
Environmental Risk Assessment.” OGRA-SO-645. Prepared by the Office of Solid Waste.
December.
U.S. EPA. 1992a. “Background for NEPA Reviewers: Crude Oil and Natural Gas Exploration,
Development, and Production.” Prepared by the Science Applications International Corporation
for the EPA Office of Solid Waste under Contract Number 68-W0-0025. Washington, DC. June.
U.S. EPA. 1992b. “Management of Wastes from Crude Oil and Natural Gas Exploration, Development,
and Production on Alaska's North Slope.” Prepared by the EPA Office of Solid Waste and
Emergency Response. Washington, DC. May.
U.S. EPA. 1993. “Diffuse NORM Wastes - Waste Characterization and Preliminary Risk Assessment.”
RAE-9232/1-2. Prepared by J. Dehmel of SC&A, Inc. and V.C. Rogers of Rogers & Associates
Engineering Corp. under Contract No. 68-D20-155 for the Office of Radiation and Indoor Air.
Washington, DC. May.
U.S. EPA. 1994. “An SAB Report: Review of Diffuse NORM Draft Scoping Document.” EPA-SAB-RAC-
94-013. Prepared by the Science Advisory Board. Washington, DC. May.
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Prepared by HydroGeoLogic, Inc. for the Office of Solid Waste. Washington, D.C. August.
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Office of Solid Waste. Washington, D.C. January.

Management of Exploration, Development and Production Wastes
Section 10: References 10-16

U.S. EPA. 2000c. “Associated Waste Report: Dehydration and Sweetening Wastes.” Prepared by the
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Washington, DC. December.
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Waste Regulations.” EPA530-K-01-004. Prepared by the EPA Office of Solid Waste. Washington,
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Office of Research and Development. Washington, DC. September.
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Energy Research Centre of the Netherlands for the Office of Research and Development under
Contract No. EP‐C‐09‐027. Research Triangle Park, NC. October.

Management of Exploration, Development and Production Wastes
Section 10: References 10-17

U.S. EPA. 2014d. “Human and Ecological Risk Assessment of Coal Combustion Residuals.” Regulation
Identifier Number: 2050-AE81. Prepared by the Office of Solid Waste and Emergency Response.
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Registry 1.0” EPA/601/R-14/003. Prepared by the EPA Office of Research and Development.
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Quality, and Management of Water Produced during Oil and Gas Production.” GAO-12-156.
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Construction Standards for Concrete Mixing and Loading Pads and Secondary Containment
Structures.” February.

Management of Exploration, Development and Production Wastes
Section 10: References 10-18

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Management of Exploration, Development and Production Wastes
Section 10: References 10-19

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in the United States.” Environmental Science and Technology. 48:8334-8348.

Management of Exploration, Development and Production Wastes
Appendix A: Damage Cases A-1

Appendix A: Damage Cases
This appendix provides a summary of the Agency’s review of damage cases discussed in Section 2
(Summary of Agency Actions) and Section 8 (Damage Cases) of the main text. EPA reviewed the
release incidents that had been submitted to the Agency, as well as any additional incidents identified
during this review, to understand the type and frequency of releases from the waste management units
that contain E&P wastes. EPA considered releases from these units that resulted in documented adverse
health impacts to humans and wildlife, impairment of habitat or degradation of natural resources. EPA
further limited this review to releases that had occurred or were ongoing in the past six years to best
reflect current management practices.
 Attachment A-1: provides a list of sources on alleged release incidents of E&P waste provided by
the Natural Resources Defense Council in the 2010 Petition for Rulemaking Pursuant to Section
6974(a) of the Resource Conservation and Recovery Act Concerning the Regulation of Wastes
Associated with the Exploration, Development, or Production of Crude Oil or Natural Gas or
Geothermal Energy.
 Attachment A-2: provides the result of the Agency’s review of damage cases, which includes
summaries of release incidents found to meet all of the review criteria, as well as those that
appeared to meet the criteria but did not have sufficient information to determine the cause of the
release, the adverse effects, or other pertinent information.

Management of Exploration, Development and Production Wastes
Appendix A: Damage Cases A-2

Attachment A-1:
List of Sources Provided by NRDC
for the 2010 Review of Damage
Cases

Management of Exploration, Development and Production Wastes
Appendix A: Damage Cases A-3

1. Joseph F. Scavetta, RCRA 101: A Course in Compliance for Colleges and Universities, 72 Notre
Dame Law Review (1997)
2. Natasha Ernst, Note, Flow Control Ordinances in a Post-Carbone World, 13 Penn State
Environmental Law Review (2004)
3. James R. Cox, Revisiting RCRA’S Oilfield Waste Exemption as to Certain Hazardous Oilfield
Exploration and Production Wastes, 14 Villanova Environmental Law Journal (2003)
4. EPA, Report to Congress, Management of Wastes from the Exploration, Development, and
Production of Crude Oil, Natural Gas, and Geothermal Energy, Volumes 1–3 EPA530-SW-88-
003 (1987)
5. Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and
Production Wastes, 53 Fed. Reg. 25 (July 6, 1988)
6. EPA Region 8, An Assessment of the Environmental Implications of Oil and Gas Production: A
Regional Case Study (Working Draft 2008)
7. 101 F.3d 772 (D.C. Cir. 1996)
8. Closing Argument of the New Mexico Citizens for Clean Air and Water, Dec. 2007, OCD
Document Image No. 14015_648_CF[1]
9. Drilling Down: Protecting Western Communities from the Health and Environmental Effects
of Oil and Gas Production (2007)
10. Railroad Commission of Texas, Waste Minimization in the Oil Field
11. Claudia Zagrean Nagy, California Department of Toxic Substances Control, Oil Exploration and
Production Wastes Initiative (2002)
12. Kelly Corcoran, Katherine Joseph, Elizabeth Laposata, & Eric Scot, UC Hastings College of the
Law’ Public Law Research Institute, Selected Topics in State and Local Regulation of Oil and
Gas Exploration and Production
13. C. Tsouris, Oak Ridge National Laboratory, Emerging Applications of Gas Hydrates
14. Letter from West Virginia Department of Environmental Protection to William Goodwin,
Superintendent Clarksburg Sanitary Board, July 23, 2009
15. Oklahoma Corporation Commission Oil and Gas Conversation Division, Guidelines for
Responding to and Remediating New or Historic Brine Spills (2009)
16. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document Nos. 1631502, 1631508
17. A.H. Beyer, Chevron Oil Field Research Co., Technical Memorandum, Purification of Produced
Water, Part 1—Removal of Volatile Dissolved Oil by Stripping (1972)

Management of Exploration, Development and Production Wastes
Appendix A: Damage Cases A-4

18. U.S. General Accounting Office, RCED-89-97, Safeguards Are Not Preventing Contamination
from Injected Oil and Gas Wells (1989)
19. Keith Schneider, Radiation Danger Found in Oilfields Across the Nation, N.Y. Times, Dec. 3,
1990
20. N.Y. Department of Environmental Conservation, Draft Supplemental General Environmental
Impact Statement (2009)
21. Abrahm Lustgarten & ProPublica, Natural Gas Drilling Produces Radioactive Wastewater,
Scientific American, Nov. 9, 2009
22. Motion in Limine to Exclude Rogers and Associates Engineering Reports, Lester v. Exxon Mobil
Corp., No. 630-402 (La. 24th Jud. Dist. Ct. 2009)
23. Wilma Subra, Louisiana Environmental Action Network, Comments on Hydraulic Fracturing
to the Louisiana Senate Environmental Quality Committee, Mar. 11, 2010
24. Susan Riha et al, Comments on the Draft SGEIS on the Oil, Gas and Solution Mining Regulatory
Program, Jan. 2010
25. U.S. Congress, Office of Technology Assessment, Managing Industrial Solid Wastes from
Manufacturing, Mining, Oil and Gas Production, and Utility Coal Combustion—Background
Paper (1992)
26. U.S. Fish & Wildlife Service, Region 6, Environmental Contaminants Program, Reserve Pit
Management: Risks to Migratory Birds (2009)
27. Oil & Gas Accountability Project, Pit Pollution—Backgrounder on the Issues, with a New
Mexico Case Study (2004)
28. U.S. Environmental Protection Agency, Technology Transfer Air Toxics: Acrylamide
29. T.A. Kassim, Waste Minimization and Molecular Nanotechnology: Toward Total
Environmental Sustainability, in 3 Environmental Impact Assessment of Recycled Wastes on
Surface and Ground Waters: Engineering Modeling and Sustainability (Tarek A. Kassim ed.,
2005)
30. Texas Railroad Commission, Waste Minimization in Drilling Operations
31. Jonathan Wills, Muddied Waters, A Survey of Offshore Oilfield Drilling Wastes and Disposal
Techniques to Reduce the Ecological Impact of Sea Dumping (2000)
32. American Petroleum Institute, Waste Management
33. Dara O’Rourke & Sarah Connolly, Just Oil? The Distribution of Environmental and Social
Impacts of Oil Production and Consumption, 28 Annual Review of Environment and Resources
(2003)

Management of Exploration, Development and Production Wastes
Appendix A: Damage Cases A-5

34. Testimony of Margaret A. Ash, OGCC Environmental Supervisor, In the Matter of Changes to
the Rules and Regulations of the Oil and Gas Conservation Commission of the State of Colorado
35. The Endocrine Disruption Exchange, Potential Health Effects of Residues in 6 New Mexico Oil
and Gas Drilling Reserve Pits Based on Compounds Detected in at Least One Sample, Nov. 15,
2007
36. Shannon D. Williams, David E. Ladd & James J. Farmer, U.S. Geological Survey, Fate and
Transport of Petroleum Hydrocarbons in Soil and Ground Water at Big South Fork National
River and Recreation Area, Tennessee and Kentucky, 2002–2003 (2006)
37. The Endocrine Disruption Exchange, Number of Chemicals Detected in Reserve Pits for 6 Wells
in New Mexico That Appear on National Toxic Chemical Lists: Amended Document, Nov. 15,
2007
38. Letter from Roy Staiger, District Office Cleanup Coordinator, Texas Railroad Commission, to
Exxon Mobil Corporation, Dec. 31, 2009
39. Oil & Gas Accountability Project, Spring/Summer 2006 Report (2006)
40. Wolf Eagle Environmental, Environmental Studies: Fugitive Air Emissions Testing, Impacted
Soil Testing, Mr. and Mrs. Timothy Ruggiero (2010)
41. U.S.G.S., Toxic Substance Hydrology Program: BTEX
42. Eric Griffey, “Toxic drilling waste is getting spread all over Texas farmland,” Fort Worth Weekly
(May 12, 2010)
43. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease
Registry, ToxFAQs for Acetone (1995)
44. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease
Registry, ToxFAQs for Arsenic (2007)
45. ScienceLab.com, Chemicals & Laboratory Equipment, Material Safety Data Sheet: Arsenic
MSDS 1 (2008)
46. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease
Registry, ToxFAQs for Barium (2007)
47. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease
Registry, ToxFAQs for Radium (2007)
48. Chris Gray, Pits Cause Stink in Lafourche, Times-Picayune, July 14, 1997
49. Miguel San Sebastian, Ben Armstrong, & Carolyn Stephens, Outcomes of Pregnancy among
Women Living in the Proximity of Oil Fields in the Amazon Basin of Ecuador, 8 International
Journal of Occupational and Environmental Health (2002)

Management of Exploration, Development and Production Wastes
Appendix A: Damage Cases A-6

50. Anna-Karin Hurtig & Miguel San Sebastian, Geographical Differences in Cancer Incidence in
the Amazon Basin of Ecuador in Relation to Residence near Oil Fields, 31 International Journal
of Epidemiology (2002)
51. Henry Spitz, Kennith Lovins & Christopher Becker, Evaluation of Residual Soil Contamination
From Commercial Oil Well Drilling Activities and Its Impact on the Naturally Occurring
Background Radiation Environment, 6 Soil & Sediment Contamination: An International
Journal (1997)
52. Joint Factual Statement, ¶¶ 10–27, U.S. v. Exxon Mobil Corp., (D.Col. 2009)
53. Bryan M. Clark, Dirty Drilling: The Threat of Oil and Gas Drilling in Lake Erie (2005)
54. Letter from Lisa Kirkpatrick, Chief, New Mexico Dept. of Game & Fish, Conservation Services
Division, to Florene Davidson, Commission Secretary, EMNRD Oil Conservation Division (Jan.
20, 2006)
55. Letter from Lisa Kirkpatrick, Chief, New Mexico Dept. of Game & Fish, Conservation Services
Division, to Florene Davidson, Commission Secretary, EMNRD Oil Conservation Division (Mar.
7, 2006)
56. Letter from Lisa Kirkpatrick, Chief, New Mexico Dept. of Game & Fish, Conservation Services
Division, to Florene Davidson, Commission Secretary, EMNRD Oil Conservation Division (Feb.
2, 2007)
57. Press Release, Pennsylvania Department of Environmental Protection, Cattle from Tioga
County Farm Quarantined after Coming in Contact with Natural Gas Drilling Wastewater (July
1 2010)
58. Amended Complaint at ¶ 32, Sweet Lake Land and Oil Co. v. Exxon Mobil Corp., No.
209CV01100, (W.D. La. filed Sept. 14, 2009), 2009 WL 4701364
59. Test results from Veterinary Medical Diagnostic Laboratory on 26 July 2005, 18 August 2005,
and 6 September 2005
60. Bluedaze: Drilling Reform for Texas, http://txsharon.blogspot.com/2008/07/more-barnett-shale-
sludge-pond.html. (July 25, 2008)
61. Susan Hylton, Drilling Waste Feud, Neighbors of Maverick Energy Services Think Water is
Being Polluted, Tulsa World, March 21, 2010
62. E&P Forum, Exploration and Production (E&P) Waste Management Guidelines (1993)
63. League of Women Voters of Tarrant County, Gas Drilling Waste-Water Disposal (2008)
64. Testimony of James E. McCartney to the 128th General Assembly, Ohio Senate Environmental
and Natural Resources Committee. Opposition Testimony on Senate Bill 165, Oct. 28, 2009
65. State Review of Oil and Natural Gas Environmental Regulations, Inc., Tennessee State Review
(2007)

Management of Exploration, Development and Production Wastes
Appendix A: Damage Cases A-7

66. FY2008 EPA Region 6 End-of-year Evaluation of the Railroad Commission of Texas
Underground Injection Control Program, with transmittal letter from Bill Luthans, Acting
Director, Water Quality Protection Division, Region 6 to Tommie Seitz, Director, Oil and Gas
Division (June 19, 2009)
67. Joe Carroll, Exxon’s Oozing Texas Oil Pits Haunt Residents as XTO Deal Nears. Bloomberg. April
16, 2010
68. New Mexico Energy, Minerals and Natural Resources Department, Oil Conservation Division,
Cases Where Pit Substances Contaminated New Mexico’s Ground Water (2008)
69. Oil & Gas Accountability Project, Groundwater Contamination
70. Kim Weber, Regarding Support of HB 1414—Evaporative Waste Facilities Regulations
71. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document Nos. 1630424, 1630426, 1630427, 1630428, 1630429, 1630430
72. Oil & Gas Accountability Project, Contamination Incidents Related to Oil and Gas
Development, Maralex Drilling Fluids in Drinking Water
73. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Report,
Document No. 1953000
74. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, NOAV Report,
Document No. 200085988
75. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document Nos. 1631518, 1631599, 2605176, 2605847
76. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document Nos. 200225543, 200225547, 200225546
77. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document No.1632846
78. COGCC Prather Springs Administrative Order by Consent
79. Toxics Targeting, Inc., Hazardous Materials Spills Information Request (2009)
80. Consent Assessment of Civil Penalty, In re Atlas Resources LLC, Dancho-Brown 4, ¶¶ AV–AZ,
Groves 8, ¶¶ BA–BE
81. Ohio Department of Natural Resources, Notice of Violation No. 1278508985, June 21, 2010.
82. Ohio Department of Natural Resources, Notice of Violation No. 2016754140, May 16, 2008.
83. Phillip Yates, Clean Air Group Contends Evaporation Ponds in Garfield County More
Dangerous than Previously Believed, Post Independent, Jan. 9, 2008

Management of Exploration, Development and Production Wastes
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84. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Complaint
Report, Document No. 200081602
85. Amended Complaint, Stephenson v. Chevron U.S.A, Inc., No. 209CV01454, (W.D. La. filed Sept.
11, 2009), 2009 WL 4701406
86. Petition for Damages, Brownell Land Corp., LLC v. Honey Well Int’l., No. 08CV04988, (E.D. La.
filed Nov. 21, 2008), 2008 WL 5366168
87. Rice Agricult. Corp., Inc., v. HEC Petroleum Inc., 2006 WL 2032688 (E.D. La)
88. Petition for Damages, Tensas Poppadoc, Inc. v. Chevron U.S.A., Inc., No. 040769, (7th Judicial
Court La. filed Sept. 21, 2005), 2005 WL 6289654
89. Petition for Damages to School Lands, Louisiana v. Shell Oil Co., No. CV04-2224 L-O, (W.D. La.
filed Oct. 29, 2004), 2004 WL 2891505
90. State Review of Oil and Natural Gas Environmental Regulations, Inc., Kentucky State Review
(2006)
91. State Review of Oil and Natural Gas Environmental Regulations, Inc., Louisiana State Review
(2004)
92. Christie Campbell, Foul Odor from Impoundment Upsets Hopewell Woman, Observer-
Reporter, Apr. 14, 2010
93. EPA Office of Compliance Sector Notebook Project, Profile of the Oil and Gas Extraction
Industry, EPA/310-R-99-006 (2000)
94. Letter from Gary M. Maslanka, New York State Division of Solid & Hazardous Materials, to
Joseph Boyles, Casella (April 27, 2010)
95. Press Release, Arkansas Dept. of Envtl. Quality, ADEQ Releases Landfarm Study Report (Apr.
20, 2009)
96. M.G. Puder & J.A. Veil, Argonne National Laboratory, Offsite Commercial Disposal of Oil and
Gas Exploration and Production Waste: Availability, Options, and Costs (2006)
97. Abrahm Lustgarten, State Oil and Gas Regulators Are Spread Too Thin to Do Their Jobs,
ProPublica, December 30, 2009
98. EPA, Office of the Inspector General, Complete Assessment Needed to Ensure Rural Texas
Community Has Safe Drinking Water, No. 2007-P-00034 (2007)
99. Robert D. Bullard, Testimony before the Subcommittee on Superfund and Environmental
Health of the Senate Environment and Public Works Committee (July 25, 2007)
100. Marcellus Gas Well Hydrofracture Wastewater Disposal by Recycle Treatment Process,
ProChemTech International, Inc.

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101. New York State Water Resources Institute, Waste Management of Cuttings, Drilling Fluids,
Hydrofrack Water and Produced Water
102. Ohio Environmental Protection Agency, Marcellus Shale Gas Well Production Wastewater
103. Joaquin Sapien, With Natural Gas Drilling Boom, Pennsylvania Faces an Onslaught of
Wastewater, ProPublica, October 4, 2009
104. Marcellus Shale Natural Gas Wastewater Treatment, Hearing Before the S. Comm. on
Environmental Resources and Energy (Pa. 2010) (statement of Peter Slack, Pennsylvania
Municipal Authorities Association)
105. Press Release, Pennsylvania Department of Environmental Protection, DEP Says Jersey Shore
Borough Exceeds Wastewater Permit Limits (June 23 2009)
106. Pennsylvania Department of Environmental Protection, Press Release, DEP Fines Atlas $85,000
for Violations at 13 Well Sites, Jan. 7, 2010
107. Laura Legere, Massive use of water in gas drilling presents myriad chances for pollution,
Scranton Times-Tribune, June 22, 2010
108. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Report,
Document No. 1630697
109. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document Nos. 1631155, 1631831, 1631794, 1632853
110. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document Nos. 1630885, 1631496, 1631519, 1632057, 2605191, 1632995
111. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports,
Document Nos. 200226284, 200225725, 2605709
112. Oil & Gas Accountability Project, Colorado Oil and Gas Industry Spills: A review of COGCC
data (June 2002-June 2006) (2006)
113. Frac Fluid Spill Reported in Flower Mound, Cross Timbers Gazette, Mar. 17, 2010
114. Letter from Robert F. Fetty, Mayor, Town of West Union, to Barbara Taylor, Director,
WVBPH/Office of Environmental Health Services, Oct. 28, 2009
115. Posting of Ken Ward Jr. to Sustained Outrage: A Gazette Watchdog Blog
116. Letter from Louanne McConnell Fatora to Governor Manchin, West Highlands Conservancy
(Aug. 30, 2009)
117. U.S. Energy Information Administration, Number of Producing Gas Wells (2009)
118. Bureau of Land Management, BLM FY 2009 Budget Justifications III-1834 (2009)

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119. Hannah Wiseman, Untested Waters: The Rise of Hydraulic Fracturing in Oil and Gas
Production and the Need to Revisit Regulation, 20 Fordham Environmental. Law Review (2009)
120. Texas Railroad Commission, Newark, East (Barnett Shale) Field, Drilling Permits Issued
121. Newark, East (Barnett Shale) Drilling Permits Issued (1993-2009), Texas Railroad Commission
122. Industry Sets Record For Drilling, Well Completions, Land Letter, Jan. 18, 2007
123. API: US Drilling at 21-year High in 1Q, Oil & Gas Journal, May 7, 2007
124. Utah Department of Natural Resources, Division of Oil, Gas and Mining, Produced Water
Disposal(2007)
125. EPA, Region 8, Oil and Gas Environmental Assessment Report 1996–2002 (2003)
126. Statement of Commissioner William Olson before the New Mexico Oil Conservation Division,
Apr. 16, 2008, OCD Document Image 14015_657_CF[1]
127. “Governor Bill Richardson Announces Oil and Gas Drilling Activity in New Mexico Is Strong:
Environmental regulations are not driving business away,” State of New Mexico, Press Release,
May 19, 2010
128. Dorsey Rogers, Gary Fout & William A. Piper, New Innovative Process Allows Drilling Without
Pits in New Mexico (2006)
129. Oil & Gas Accountability Project, Alternatives to Pits
130. Oil & Gas Accountability Project, Notice of Errata in the Oil & Gas Accountability Project’s
Closing Argument and Proposed Changes, Re: Case 14015: Application of New Mexico Oil
Conservation Division for Repeal of Existing Rule 50 Concerning Pits, etc., Dec. 11, 2007, OCD
Document Image No.14015_654_CF[1]
131. Dorsey Rogers, Dee Smith, Gary Fout & Will Marchbanks, Closed-loop drilling system: A Viable
Alternative to Reserve Waste Pits, World Oil, Dec. 2008
132. Exhibit 8, Closed-Loop Drilling Case Studies, Re: Case 14015: Application of New Mexico Oil
Conservation Division for Repeal of Existing Rule 50 Concerning Pits, etc., OCD Document
Image No. 14015_637_[CF]1
133. Abrahm Lustgarten, Underused Drilling Practices Could Avoid Pollution, ProPublica, Dec. 14,
2009
134. U.S. Fish & Wildlife Service, Wildlife Mortality Risk in Oil Field Waste Pits, U.S. FWS
Contaminants Information Bulletin (2000)
135. Bureau of Land Management, The Gold Book: Surface Operating Standards and Guidelines for
Oil and Gas Exploration and Development (4th ed. 2007)

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136. Controlled Recovery Inc.’s Written Closing Argument, Re: Case 14015: Application of New
Mexico Oil Conservation Division for Repeal of Existing Rule 50 Concerning Pits, etc., Dec. 10,
2007
137. Lowell Brown, Officials Give Few Answers to Argyle, Denton Record-Chronicle, Jan. 30, 2010
138. E&P Forum/UNEP Technical Publication, Environmental Management in Oil and Gas
Exploration and Production: An Overview of Issues and Management Approaches (1997)
139. STW Resources, Inc., Contaminated Waste Water Reclamation Opportunities
140. Railroad Commission of Texas, News Release, Commissioners Approve of Devon Water
Recycling Project for the Barnett Shale, July 29, 2008
141. Energy Companies Strive to Reuse Water, Weatherford Telegram, July 25, 2007
142. Nine New Projects, Oil & Gas Program Newsletter (U.S. Dept. of Energy, National Energy
Technology Lab), Winter 2009
143. Katie Burford, ExxonMobil Favors Fracing Disclosure, Environmental Group Welcomes
Position from Oil Industry Giant, Durango Herald, Apr. 19, 2010
144. Drilling Waste Management Information System, Drilling Waste Management Fact Sheet: Using
Muds and Additives with Lower Environmental Impacts
145. Schlumberger, Earth-friendly Green Slurry system for uniform marine performance, March
2003
146. Rifle, Silt, New Castle Community Development Plan, January 1, 2006
147. EPA, RCRA Orientation Manual, Chapter III: RCRA Subtitle C—Managing Hazardous Waste,
Hazardous Waste Identification.
148. Hazardous Waste Treatment Council v. U.S. EPA, 861 F.2d 277, 279 (D.C. Cir. 1988)
149. U.S. Dept. of Labor, Occupational Safety & Health Administration, Potential Flammability
Hazard Associated with Bulk Transportation of Oilfield Exploration and Production (E&P)
Waste Liquids, SHIB-03-24-2008
150. Janice Crompton, Residents Reported Gas Odors Before Explosion, Pittsburgh Post-Gazette,
Apr. 1, 2010
151. Kathie O. Warco, Fumes Ignite at Gas Well, Observer-Reporter, Apr. 1, 2010
152. Earthworks, OCD’s 2007 Pit Sampling Program: What is in That Pit?

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Appendix A: Damage Cases A-12

Attachment A-2:
Summary of Recent Damage Cases

[Due to the file size, this spreadsheet is maintained as a separate file.]

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-1

Appendix B: Constituent Database
This appendix provides a summary of the data collection efforts conducted in support of this document.
The intent of the literature review is to assemble existing data that can form the basis for conclusions
about the composition and behavior of wastes generated by exploration, development and production
(E&P) operations. The data review process, as well as the rationale for exclusion of any data from the
assembled sources, is discussed in the following sections. The citations in this appendix address only
those sources cited in the body of this appendix. The E&P Database contains a full list of the citations
associated with the dataset.
 Attachment B-1: provides the E&P Database, which contains the constituent data relied upon in
tis review to characterize concentrations present in and released from the different waste types.
B.1. Data Collection
EPA reviewed the available literature for studies that contained information on E&P waste. This initial
review focused on publicly available data that that could be reasonably assembled without more formal
information collection efforts. The purpose of this current effort was to determine whether the
available data is sufficient to draw conclusions about E&P wastes and where additional data is needed
to understand the impacts to human health and the environment that may result from the current
management practices for these wastes.
Some potentially relevant sources were already available from previous Agency investigations. EPA
supplemented these sources with reports drawn from the webpages other federal and state agencies
with jurisdiction over oil and gas well permitting, operation and/or waste management. EPA first
reviewed these sources to develop a baseline understanding of the current universe of waste types,
waste composition and drilling practices to focus further searches. EPA then queried multiple databases
of peer-reviewed literature, such as Science Direct, with various combinations of descriptive keywords
to capture the different wastes (e.g., produced water), constituents (e.g., radium) and drilling practices
(e.g., hydraulic fracturing). Finally, EPA reviewed the citations from each study to identify any
additional sources that had not yet been captured during the review. Once the citations list had been
exhausted, EPA reviewed the identified studies, updated the baseline search terms, and repeated the
literature search. This process was repeated until no new sources of information were identified.
B.2. Data Quality Review
EPA reviewed all the literature sources assembled to ensure that the data from each were of sufficient
quality to form a basis for conclusions on the composition and behavior of E&P waste. The following
subsections detail how the Agency applied the data quality assessment factors outlined in A Summary
of General Assessment Factors for Evaluation the Quality of Scientific and Technical Information
(U.S. EPA, 2003). The following subsections detail the review for each major assessment factor. When
it was determined that data from a particular study was not relevant, it was excluded from the database.

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-2

When individual data points or entire studies were found to introduce an unacceptable level of
uncertainty, these data were filtered out from the dataset prior to any analyses. However, these data
were left in the database for future reference.
B.2.1 Evaluation and Review
Evaluation and review is the extent to which the findings of a given study have undergone sufficient
independent verification, validation and peer review. An independent review is one conducted by
technical experts who were not associated with the generation of the work under review either directly
through substantial contribution to its development, or indirectly through significant consultation
during the development of the work. Independent review is intended to identify any errors or bias in
how data are collected, handled or interpreted, and also to ensure that the findings are accurate and
reliable.
Data reported in grey literature has not necessarily undergone formal peer review, though some have
been made publicly available for review and comment as part of past Agency rulemakings. Most of the
data were collected in accordance with standardized analytical methods that have been validated. EPA
relied primarily on raw data from these studies. Any further analyses of the data were only considered
as supplementary lines of evidence to corroborate conclusions drawn from the data. External review of
each study in isolation would not provide any indication whether the raw data are appropriate for the
current application. Instead, EPA relied on other quality metrics to determine whether data was fit for
purpose. EPA only excluded data from one study as a result of the level of evaluation and review. One
study reported a large amount of leachate data for various wastes collected by a secondary source, but
noted that only a subset of the data had been independently validated (LADNR, 1999). EPA retained
all of the reported data in the E&P Database, but filtered our all non-validated samples prior to any
analyses.
B.2.2 Applicability and Utility
Applicability and utility is the extent to which the data are relevant for the intended use. This means
the purpose, design and findings of the study support the intended application of the data. EPA
reviewed the assembled studies to ensure that the data contained in each are representative of
generated E&P wastes and environmental conditions relevant to anticipated waste management
scenarios.
Waste Type:
Data collection was focused on the wastes generated from E&P activities. Some studies reported data
for samples outside of this scope. These data often reflected wastes generated at downstream refineries.
These wastes may be similar in appearance to those generated at the drilling site, but the composition
can be different as a result of losses during storage (e.g., volatilization) or treatment at the refinery to
produce a salable product. This represents a major source of uncertainty and so these data were
excluded from the E&P Database.

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Appendix B: Constituent Database B-3

EPA further focused the literature review on the waste types with the greatest amount of data available.
These tended to be those either generated in the greatest volume (e.g., produced water) or those that
pose specific management issues (e.g., well scale). There are a number of additional wastes generated
during the course of E&P activities, such as rig wash (U.S. EPA, 2002). Little characterization data was
identified for many of these additional wastes and so no conclusions could be drawn about the typical
composition of these additional wastes.
Many studies reported data on individual E&P waste types as generated (e.g., drill cuttings), but others
reported data on E&P wastes after management with other E&P wastes (e.g., drilling solids) or
treatment in anticipation of disposal (e.g., stabilization/solidification). All of these samples can provide
useful information about the impact of management practices on waste composition and behavior.
Therefore, EPA retained all the different sample types in the database, but flagged the relevant
differences to facilitate comparison.
Country of Origin:
When reviewing the available literature, EPA drew data from any well drilled in North America. The
country of origin was labeled for each sample in the E&P Database. It is unknown whether wastes from
Canada or Mexico are substantially different from those in the United States given the sparseness of
available data. However, if relationships exist between geology and waste composition as anticipated,
then these data can still provide useful information. Therefore, EPA included data from Canada and
Mexico in the E&P Database. These data were used to identify relationships between constituents, but
were not incorporated in any summary statistics. Data from countries outside of North America were
not incorporated in the database, but were considered as a secondary source of information to
supplement discussion and corroborate findings. These international sources are cited in the main text
where applicable.
Well Type:
EPA drew data for all well types during the review of the available literature, including wells used as a
source of potable water and brine where the water produced is a valuable product instead of a waste.
Some of these wells fall outside the scope of this document, but if relationships exist between geology
and waste composition as anticipated, these data can still provide useful information. EPA incorporated
the data for these other wells in the E&P Database with the well type flagged. Because these other well
types are only used to supplement the waste data, EPA did not aim for a comprehensive review of the
literature. Therefore, care should be taken when drawing any conclusions from the database about
typical water composition from these wells.
B.1.1 Soundness
Soundness is the extent to which the methods employed by a literature source are reasonable and
consistent with the intended application of the data. This means that any methods used to collect and
measure data have demonstrated the technical ability to reliably and repeatedly achieve desired levels
of accuracy and precision, and that any methods used to analyze and interpret data, such as equations;

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-4

models and simplifying assumptions, are adequately justified and rooted in accepted scientific
principles.
Analytical Methods:
EPA reviewed the analytical methods used by each study to measure constituent levels in each waste.
The purpose of this review was to determine whether the uncertainties associated with reported data
could affect the conclusions in this document. The methods used by different studies varied based on
the focus of the study and the equipment available to the authors. A few studies did not report the
methods used or only noted that the samples had been sent to the U.S. Department of Interior
Geological Survey or another certified laboratory for analysis.
One consideration in this review was whether the methods used by a study accurately measured the
constituent levels in an E&P waste. Methods that are not well-suited for high ionic strength wastes
may result in imprecise data. For example, methods that dilute the waste prior to measurement can
result in high detection limits for minor constituents (MSC, 2009), while those that precipitate
constituent mass out of solution prior to measurement may underestimate constituent levels as a result
of matrix interference (Nelson et al., 2014). The extent to which these uncertainties might affect the
data is not known. Therefore, at this stage of investigation, EPA relied on other metrics, such as charge
balance and agreement with observed relationships, to identify potential data quality concerns and
avoid exclusion of useful data. If data from these studies were incorrectly measured, the error is likely
to be reflected in the calculated charge balance. Therefore, EPA did not filter out any data solely
because of the specific analytical method reported.
Another consideration in this review was whether the study provides data appropriate for the intended
use. Some analytical methods are designed to measure different aspects of waste composition. For
example, non-destructive methods (e.g., neutron activation analysis) measure the total constituent mass
within the sample matrix, while digestion methods (e.g., mass spectrometry) measure the constituent
mass that can be liberated from the matrix with a combination of heat and acid. Both types of data can
provide useful information on waste composition and behavior. Total concentrations measured by non-
destructive methods better reflect the entire waste and can be used to demonstrate relationships among
constituents in the total waste. The acid-extractable concentrations measured by digestion methods
better reflect the fraction of the waste that is available to be released into the surrounding environment
and can be used to estimate exposures. The resulting data are not necessarily equivalent and care should
be taken before combining these data in a single dataset. Therefore, EPA compared data collected with
different methods to determine if substantial differences exist. When such differences were identified,
EPA separated the data out for further review and discussion in the text of this analysis.
B.1.2 Clarity and Completeness
Clarity and completeness is the degree to which a study transparently documents all assumptions,
methods, results, and other key information. An evaluation that is both clear and complete provides
enough detail that an outside party with access to the necessary resources can replicate the analyses.

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-5

Units:
Studies reported the data in variable units. Some expressed concentrations in terms of mass or molarity,
while others reported concentrations per unit of volume or mass. All concentrations were converted
into units of milligrams (mg) or picocuries (pCi) per liter (L) or kilogram (kg), based on the relevant
media. Sometimes this conversion required the use of additional data or assumptions. For example,
when density was not reported for an aqueous sample expressed per unit of mass, a density of 1.0 kg/L
was used to convert to a volumetric concentration. This may result in an underestimation of
concentration for some samples, as produced water density has been reported as high as 1.3 kg/L.
However, the magnitude of this uncertainty is small in comparison to the orders-of-magnitude
variability observed among the larger dataset. Any time that additional data or assumptions were
required to calculate the concentration, the approach was flagged in the notes column of the database.
In instances where data was insufficient to convert the reported units to mg/L with any certainty
(e.g., reported in units of chemical activity), the samples were excluded from the database entirely.
EPA identified two separate studies with indeterminate units for some samples. Both of these studies
reported data for produced water. The first study, USEPA (2016a), reported data obtained from the
Wyoming Oil and Gas Conservation Commission. Despite outreach to the Commission, EPA could not
confirm units for many minor constituents. As such, EPA filtered out the constituents with uncertain
units prior to the any analyses. The second study, U.S. DOI (2016), is a database compiled from sources
assembled by the United States Geological Survey and other organizations.B1 In this second study, all
of the data is reported to be in units of milligrams or picocuries per liter. Yet during the literature
review, EPA identified one source document (U.S. DOI, 1975) that had since been included into a
dataset flagged in the database as “USGSBREIT.” All the values reported in this study are identical to
those in the database, but the minor constituents are reported in μg/L. Given that the units of the major
ions are correct and the number of minor analytes reported are limited, the calculated charge balance
may not always be sufficient to screen out this type of error. Therefore, EPA filtered out all minor
constituents from USGSBREIT data prior to calculation of summary statistics. For clarity, only the
USGSBREIT data was labeled as U.S. DOI (2016) in the E&P Database. Other data for which the original
source could be located were incorporated in the E&P Database under that citation and flagged as
originating from U.S. DOI (2016) in the notes column.
Raw Data:
During review of the assembled literature, EPA found that some authors chose to provide summary
statistics instead of full datasets. EPA made an initial effort to reach out to a few authors to obtain the
underlying data, but received few responses. While summary statistics provide some understanding of
the overall distribution of a dataset, it is difficult to incorporate these data along with other individual
data points. In particular, the presence of extreme values (e.g., maximum, minimum) can greatly skew
analyses. The highest value for one constituent may not correspond to the highest value for another,

B1) This database is periodically updated and has been at least once since the E&P database was compiled. The most recent version
of the database was not incorporated into the current analysis due to time constraints. However, it is not anticipated to affect the
conclusions of this document.

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-6

and so extreme values may mask relationships within the data. Therefore, while all of the reported
summary statistics were incorporated into the E&P Database, extreme values were filtered out prior
from all current analyses. The limited number of mean or median values were incorporated into the
analyses as individual data points. When known, the total number of individual samples captured by
the summary statistics is also reported in the notes column of the database.
Drilling Method:
The largest shift in drilling practices in the past several decades has been the adoption of directional
drilling in formations previously considered uneconomical to access. The greater consolidation that
occurred in these formations trapped the natural gas in isolated small, poorly connected pore spaces
that make it difficult to liberate. This consolidation also results in greater evaporation of water from
the formation, which may result in higher dissolved constituent levels (concentration and activity) in
the remaining water. In addition, the greater distance drilled through high organic and metal shale
during horizontal drilling could further concentrate constituent mass in the resulting waste. Therefore,
where possible, EPA separated out samples from vertical and horizontal wells for further review and
discussion in the main text. Some studies did not specify the orientation of sampled wells and so, unless
otherwise specified, EPA assumed all samples collected prior to the year 2000 were from vertical wells.
Although horizontal drilling has been an available technology for nearly a century beforehand, it was
not in widespread use until the early 2000s (EIA, 2018a). It is known that vertical wells can also be
sited in lower-permeability formations and that some are hydraulically-fractured. However, few
studies noted whether or not a vertical well had been fractured. Therefore, this remains a source of
uncertainty in the dataset. However, the greater tendency for vertical wells to be sited in more
permeable formations makes it likely that any differences that exist based on the type of formation will
still be apparent in comparisons.
The equipment used to install and operate wells may also affect the waste composition. For example,
additional constituent mass may be intentionally injected into a well or inadvertently leached from
pipes and other equipment in contact with the waste. However, it can be difficult to attribute elevated
constituent levels to one of these sources because studies often do not report the specific equipment
and practices used at each site. In the case of additives, this information may not be available because
it is often claimed as confidential business information (U.S. EPA, 2016b). Yet, even if this information
were available, it would be difficult to attribute moderate increases in constituent levels to specific
sources without representative samples from wells with and without those sources. In instances where
one or more samples were found to be considerably higher than the remaining dataset, EPA reviewed
the available information on drilling methods and the available literature to identify and discuss any
potential sources.
B.1.3 Variability and Uncertainty
Variability and uncertainty is the extent to which a literature source effectively characterizes, either
quantitatively or qualitatively, these two factors in the procedures, measures, methods or models used.
Proper characterization of the major sources of variability and uncertainty provides greater confidence

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-7

that the data are can form the basis for sound conclusions. The data drawn from each literature source
is limited in the number of samples or geographical scale. Therefore, no single study can be said to
provide a statistically representative sample. However, there is no reason to exclude any individual
sample because it does not fully capture the variability of a waste. More data ensures better
characterization of the waste types. Therefore, EPA retained data from all of the available studies found
to be of sufficient quality.
Age of Sampled Waste:
The composition of a waste is not always static. For example, water present in hydrocarbon formations
often exists under reducing conditions, as well as high temperature and pressure. As a result, the
conditions surrounding the water will change dramatically before it can be analyzed in a laboratory.
Some of these changes occur rapidly, but others can occur gradually over the days or months that the
waste is stored. One example is the gradual transfer of CO2 and O2 between produced water and the
atmosphere, which can shift the water pH and result in production of insoluble oxides and carbonates
(DOE, 2004). Barium has been shown to precipitate as barite over the course of months, long after the
temperature and pressure of the water has equilibrated (Kraemer and Reid, 1984). This precipitate will
gradually add to the mass of sludge and scale. Over the same time, organic compounds and radioisotopes
in the wastes will degrade through natural processes.
Many samples reported in the literature are collected soon after generation; however, E&P wastes can
be stored on-site for some time prior to disposal. Studies rarely specify the amount of time that has
elapsed since the waste was generated. This type of information may not have been made available to
the samplers. In addition, waste generation is an ongoing process and so samples collected from
downstream pits and tanks will reflect a mixture of the waste generated over some period of time. This
represents a major source of variability and uncertainty that is difficult to address. EPA identified one
instance where anomalous data can be attributed to sample age. The comparison of 226Ra and 228Ra
activities in produced water found the 228Ra activities reported by Shih et al. (2015) to be low relative
to the remaining samples. This study reported secondary data from the Pennsylvania Department of
Environmental Protection, which did not provide information on the age of the samples. 228Ra has a
predictable half-life (5.8 years), which is far less than the corresponding half-life for 226Ra (1,600 years).
Thus, as the sample ages, 228Ra will become depleted relative to 226Ra. Given the isolation of these low
values to a single study and the strong correlation observed in the remaining studies, EPA concluded
that sample age is the most likely explanation. Therefore, EPA filtered out the samples of 228Ra from
this study prior to any analyses. Samples of 226Ra were retained because the much longer half-life
eliminates the likelihood of similar issues from decay.
Age of Reported Data:
The studies identified with relevant characterization data were published over the span of a full century
between 1917 and 2017. The oldest studies predominantly sampled produced water that was analyzed
only for major constituents (e.g., chloride). These older studies may include samples drawn from
formations that are no longer in production. It is possible the wastes from these formations differ from

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-8

those generated today. However, available data show a considerable overlap in the major ion
composition of produced water from various states. Thus, while there is some uncertainty associated
with older studies, it is believed the data can still provide a reasonable order-of-magnitude estimate of
major constituent levels that can be generated by a well. Furthermore, there is an equal amount of
uncertainty associated with formations that have yet to be drilled. Therefore, inclusion of data from
older formations can help ensure that the range of potential constituent levels is captured in the dataset.
Therefore, EPA did not filter out any data solely as a result of the date the study was completed.
Sample Collection Location:
More than 10,000 new oil and gas wells are drilled each year in the United States (EIA, 2018b). It is not
feasible to collect waste samples associated from every well currently in production and so any analysis
must aim for a representative subsample. However, some authors do not have the authority to compel
sampling and relied on the cooperation of facilities to obtain access to drilling sites. Other authors
selected sample locations based on areas known to have elevated constituent levels. As a result, the
sample locations reflected in the data are not truly random. This has the potential to bias the reported
data, but the extent to which this uncertainty might affect the overall dataset is not known.
Another source of uncertainty is the spatial variability of wastes within the sampled pits and tanks.
Solids suspended in produced water can settle out quickly once the velocity of the flow slows at the
outfall to a pit or tank. This may result in hotspots of some constituents within the management units.
Concentrations can also vary based on which piece of equipment is sampled and where. Heavier solids
and organics are likely to settle out in equipment early in the production stream, while precipitation is
likely to dominate deposition in pits and tanks used for water storage. Although constituent levels may
be higher in some areas, it is unknown to what extent this will impact the overall composition of the
waste when it is aggregated for disposal.
B.3. Data Management
Once all of the identified data were assembled in the E&P Database, some additional management steps
were taken prior to analyses. The following steps were taken to mitigate sources of variability and
uncertainty that could be reliably identified and effectively managed.
Charge Balance:
Aqueous solutions must be electrically neutral. Thus, the net charge of positive ions (i.e., cations) and
negative ions (i.e., anions) must be equal. The charge balance of a solution is the difference between
the measured charge of cations and anions in a sample, expressed as a percentage of the total charge. If
the calculated charge balance is not zero, it might indicate there was an error during measurement.
One potential source of error associated with fluid E&P wastes is high total dissolved solids, which can
interfere with measurements if instruments are not properly calibrated.
There are a number of reasons why the charge balance calculated for a sample is not exactly zero. A
study may not analyze for every constituent that contributes charge or there may be interference from

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-9

other constituents during measurement. Therefore, it is common to calculate the charge balance with
a select set of dominant ions and value to a cutoff somewhat higher than zero to determine whether
there are concerns about the reported concentrations. EPA selected a cutoff of ±15% for this document
based on the previous work in the National Produced Waters Geochemical Database (U.S. DOI, 2016).
Prior to any analyses of aqueous wastes, EPA filtered out all samples with a charge balance outside of
this range.
It is clear that the high charge balance calculated for some studies is primarily the result of the absence
of data for one or more of the major ions (e.g., chloride). This was typical when the focus of a study
was a specific set of constituents, such as radioisotopes. This does not necessarily mean there are
concerns about the quality of these data, but it is not possible to demonstrate otherwise. Therefore,
EPA still filtered out any samples that did provide chloride or sodium concentrations, but flagged these
samples in the database. Further review found that inclusion of these additional samples did not
substantially shift the calculated summary statistics and so these samples are not further discussed in
this document.
Redundant Data:
Some studies reported secondary data drawn from other studies. This has the potential to bias the
overall dataset toward samples reported across a greater number of studies. Some studies also do not
provide relevant background information for secondary data. Therefore, where possible, EPA obtained
and cited to the original source of the data for reference. Any data found to be redundant between two
or more studies was removed from the database. In instances where multiple studies provided data for
different constituents from the same sample, EPA combined the data from the studies into a single
entry in the E&P Database and cited to both studies.
To identify redundant data, EPA reviewed the text of each study for citations associated with the
reported data. However, some studies did not specify that the reported data was drawn from other
studies, particularly in cases where the author(s) built on previous work. To identify this type of
redundant data, EPA compared individual samples in the database to identify cases where two or more
samples had almost the same value for all of the major ions. To instances where authors rounded exact
values. When concentrations were found to be close, other information about the samples was used to
confirm that the samples were redundant (e.g., sample date, county).
Detection Limits:
A detection limit is the lowest quantity or concentration of a constituent that can be reliably detected
with a given analytical method. When a constituent is not detected above this limit, the analytical
results are typically reported as less than the detection limit because the potential still exists for the
constituent to be present at lower levels. Such values are referred to as “left-censored.” The detection
limit varies among studies because of differences in the methods used to prepare samples, the sensitivity
of analytical instruments, and interference from solid media or other chemical constituents. EPA
incorporated all left-censored data in the E&P Database and flagged it with “<” in front of the reported
detection limit.

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-10

Ideally, left-censored data should be the lowest values in a given dataset. However, there are instances
in the database where detection limits are higher than any measured samples. This does not mean that
the data are of poor quality. For example, the sequential dilution necessary to analyze highly saline
water can result in high detection limits for minor elements. High detection limits introduce a great
amount of uncertainty into the evaluation and can bias the overall dataset high. To mitigate this
uncertainty, EPA filtered out any non-detect values that greater than the 90th percentile of detected
data prior to analysis. This cutoff was selected to strike a balance, as elimination of all non-detect data
would only bias the remaining dataset even higher. EPA incorporated the remaining non-detect values
using half of the reported detection limit based on the recommendations in Risk Assessment Guidance
for Superfund Part A (US EPA, 1989) and with the Guidance on Handling Chemical Concentration
Data near the Detection Limit in Risk Assessments (US EPA, 1991). More robust methods are available
to manage non-detect data, though these methods often rely on detected data to help backfill censored
data, which can be confounded by a small datasets. Therefore, the selected approach is considered
reasonable for current purposes of providing a first-order summary of available data.
In a few instances, concentrations were reported at higher concentrations than could be measured by
analytical instruments. This typically occurred when an element, such as iron or barium, comprised a
majority of the mass in samples of drill cuttings, sludge and well scale. EPA incorporated these data in
the E&P Database flagged with “>” in front of the reported detection limit. The range of potential
concentrations greater than a specified value is typically far wider than those below and so the
uncertainty associated with right-censored data is often greater. Therefore, all right-censored data were
filtered out prior to any analyses. Given the small number and types of samples with such high
concentrations, it was determined that the removal of these samples would not affect the conclusions
of this document.
Some studies flagged non-detects only as “ND” and did not report the associated numerical detection
limit. It is not possible to draw conclusions about likely constituent levels in these samples. EPA
incorporated the data as “ND” in the E&P Database to show that the study had analyzed for that
constituent. However, these samples were not included in sample counts presented in the main text.
Duplicate Samples:
Duplicate samples are two or more field samples intended to represent the same source, which are
collected and analyzed in a comparable manner. For a number of reasons, such as heterogeneity of the
source material and precision of analytical equipment, values measured for these samples may not be
identical. EPA treated all samples collected from the same location (e.g., wellhead, storage tank) as
duplicates, regardless of whether the samples were collected as part of separate studies or at different
times. This was done to avoid biasing the summary statistics towards wells that had been more heavily
sampled. Prior to any analysis, EPA averaged all duplicate values for each well. Where duplicates data
were a mixture of detect and non-detect values, the non-detect values were set to half the detection
limit and averaged along with detected values. The resulting, averaged value was flagged as a detected
value for the summary statistics.

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-11

One study provided discharge monitoring reports over time (U.S. EPA, 2013). This database includes
data for multiple states, but only the data for Wyoming was found to be useful based on the reported
analytes. The database included a number of sample collected at different dates, but the samples were
not always measured for the same analytes. This would likely cause many of the individual samples to
be filtered out as a result of a high charge balance. Further review of the data found that the constituent
levels reported over time did not vary dramatically. Therefore, to make best use of the available data
and to keep data entry manageable, EPA averaged all of the data reported for a single location prior to
incorporating the data in the E&P Database.
A few studies reported a large number of samples with many apparent duplicates (U.S. EPA, 2016; U.S.
DOE, 2017; U.S. DOI, 2017). However, none of these studies flagged duplicate samples. Instead, EPA
inferred the presence of duplicates from other available information, such as well names. These studies
did not always maintain consistent reporting for well names and so matching by name would have to
be conducted manually. Instead, EPA first matched samples based on GIS coordinates. The resolution
of the reported coordinates is unknown and so this approach may combine multiple wells that are
located in close proximity, but the uncertainty associated with this error is considered minimal because
the wells still reflect the same general region. Where GIS coordinates were not available, EPA manually
compared the reported well names and flagged those with similar names (e.g., Well #1 and Well
Number One). When neither GIS coordinates or well names were available, samples located in the
same county were flagged a duplicates.
B.4. Data Summary
The current literature review identified over 700 unique studies, of which 228 contained some relevant
data that were included in the E&P Database. Each study reported data on a different combination of
constituents based on the focus of that individual study. As a result, the total amount of data available
for each constituent can be quite variable. Some inorganic constituents were not reported in any of the
studies and so are not listed in the database. However, the absence of data does not necessarily indicate
these constituents are not present. Conversely, there a large number of organic compounds reported
sporadically in the literature that are not included in the database. The limited amount of data for a
large number of compounds limits the conclusions that can be drawn from the data. Therefore, EPA
focused data collection efforts on benzene, toluene, ethylbenzene and xylene because these compounds
are known byproducts of hydrocarbon formation and are the most commonly measured compounds in
the literature. EPA chose to provide a qualitative discussion on the magnitude and frequency of
detection of other organic compounds.
During the review of assembled data, EPA identified multiple major sources of uncertainty. Yet because
the range of reported constituent levels varies by orders of magnitude, it can be difficult to distinguish
between measurement uncertainty and natural variability. Therefore, EPA did not attempt to define
fully representative distributions for any constituent. Instead, the statistics presented in this document
are intended only to summarize the available data and allow a more general order-of-magnitude
comparison between datasets. Despite the uncertainty associated with the current dataset, EPA

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-12

identified strong trends among the data that indicate the existence of relationships between different
constituents that are tied to chemistry and geology, rather than the unique features of individual
formations. The likelihood that such strong relationships would erroneously emerge from the noise of
numerous independent studies is exceedingly small. Therefore, EPA concludes that the sources of
uncertainty in the dataset do not impact the main conclusions in this document and that the data are
fit for purpose. Although these data provide useful information for the current discussion, inclusion of
a particular study in the database at this stage does not indicate that it will form the basis for future
conclusions about waste composition and behavior as more data become available.
B.5. References
Kraemer, T.F. and D.F. Reid. 1984. “The Occurrence and Behavior of Radium in Saline Formation
Water of the U.S. Gulf Coast Region.” Isotope Geoscience. 2:153-174.
LADNR (Louisiana Department of Natural Resources). 1999. “TCLP Characterization of Exploration
and Production Wastes in Louisiana.” Prepared by D.D. Reible and K.T. Valsaraj of Louisiana State
University for LADNR. March.
MSC (Marcellus Shale Coalition). 2009. “Sampling and Analysis of Water Stream Associated with the
Development of Marcellus Shale Gas.” Prepared by T. Hayes of the Gas Technology Institute. Des
Plaines, IL. December.
Nelson, A.W., D. May, A.W. Knight, E.S. Eitrheim, M. Mehrhoff, R. Shannon, R. Litman and M.K.
Schultz. 2014. “Matrix Complications in the Determination of Radium Levels in Hydraulic
Fracturing Flowback Water from Marcellus Shale.” Environmental Science and Technology
Letters. 1:204-208.
Shih, J., J.E. Saiers, S.C. Anisfeld, Z. Chu, L.A. Muehlenbachs, and S.M. Olmstead. 2015.
“Characterization and Analysis of Liquid Waste from Marcellus Shale Gas Development.”
Environmental Science and Technology. 49:9557−9565
U.S. DOE (United States Department of Energy). 2004. “Evaluations of Radionuclides of Uranium,
Thorium, and Radium Associated with Produced Fluids, Precipitates, and Sludges from Oil, Gas,
and Oilfield Brine Injections Wells in Mississippi.” Prepared by C. Swann of the Mississippi Mineral
Resources Institute, J. Matthews and J. Kuszmaul of the University of Mississippi, and R. Ericksen
under award No. DE-FG26-02NT 15227. March.
U.S. DOE. 2017. “Argonne Geothermal Geochemical Database v2.0” [Database]. Prepared by C. Harto
of the Argonne National Laboratory. Published on 8/29/17.
U.S. DOE. 2018a. “Hydraulically Fractured Horizontal Wells Account for Most New Oil and Natural
Gas Well." EIA Today in Energy. Prepared by T. Cook, Jack Perrin and D. Van Wagener of the
Energy Information Administration. Published on 1/30/18.
U.S. DOE. 2018b. “Crude Oil and Natural Gas Exploratory and Development Wells." [Spreadsheet].
Prepared by the Energy Information Administration. Published on 8/20/2018.

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-13

U.S. DOI (United States Department of the Interior). 1975. “Chemical Analyses of Ground Water for
Saline-Water Resources Studies in Texas Coastal Plain Stored in National Water Data Storage and
Retrieval System – Volume 1.” Open File Series 75-79. Prepared by the United States Geological
Survey. Bay St. Louis, MS. March.
U.S. DOI. 2016. “U.S. Geological Survey National Produced Waters Geochemical Database v2.2.”
[Database]. Prepared by M.S. Blondes, K.D. Gans, M.A. Engle, Y.K. Kharaka, M.E. Reidy, V.
Saraswathula, J.J. Thordsen, E.L. Rowan and E.A. Morrissey of the United States Geological
Survey. Published on 02/16/16.
U.S. DOI. 2017. “Global Geochemical Database for Critical Metals in Black Shales: USGS Survey Data
Release” [Database]. Prepared by M. Granitto, S.A. Giles, and K.D. Kelley of the United States
Geological Survey. Published on 11/13/17.
U.S. EPA (United States Environmental Protection Agency). 1989. “Risk Assessment Guidance for
Superfund (RAGS) Part A.” EPA 530-SW-88-002. Prepared by the EPA Office of Emergency
Response. Washington, DC.
U.S. EPA. 1991. “EPA Region 3 Guidance on Handling Chemical Concentration Data Near the
Detection Limit in Risk Assessments.” EPA/903/8-91/001. Region 3. Philadelphia, PA.
U.S. EPA. 2002. “Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous
Waste Regulations.” Prepared by the EPA Office of Solid Waste. Washington, DC.
U.S. EPA. 2013. “Technical Development Document for the Coalbed Methane (CBM) Extraction
Industry.” EPA-820-R-13-009. Prepared by the EPA Office of Water. Washington, DC. April.
U.S. EPA. 2016a. “Wyoming Oil and Gas Conservation Commission (WY OGCC) Water Data
Memorandum.” DCN SGE01244. Prepared by J.K. O’Connell and S. Yates of the Eastern Research
Group, Inc. for Prepared by the EPA Office of Water. Washington, DC. February.
U.S. EPA. 2016b. “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water
Cycle on Drinking Water Resources in the United States.” EPA-600-R-16-236Fa. Prepared by
the EPA Office of Research and Development. Washington, DC. December.

Management of Exploration, Development and Production Wastes
Appendix B: Constituent Database B-14

Attachment B-1:
E&P Constituent Database

[Due to the large file size, this database is maintained as a separate file.]

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-1

Appendix C: State Programs
This appendix provides a summary of the Agency’s review of state programs discussed in Section 6
(State Programs) of the main text. The intent of this review is to better understand how state
regulations currently address management of wastes from exploration, development and production
operations and to highlight inconsistencies, lack of specificity, or possible gaps in coverage. The
following text provides a summary of state programs, broken out into 12 general topic areas and 61
specific elements. The summaries in this appendix are organized by each individual state, presented in
order of production (highest to lowest) based on the 2016 production data from the U.S. DOE Energy
Information Agency.
 Attachment C-1: provides the results of the Agency’s binary (yes/no) determination whether
regulations related to each of the 61 regulatory elements are in place for the states reviewed.
 Attachment C-2: provides a detailed spreadsheet that contains excerpts from state regulatory
text, organized by topic area and with links to the full regulatory text, that form the basis for
this review. All links provided in the spreadsheet were active at the time the spreadsheets
were compiled.
C.1. Texas
In 2016, Texas accounted for approximately 32% of the nation’s oil and gas production according to the
U.S. Energy Information Agency. It is by far the largest oil and gas producing state in the U.S. with
almost three times more production then the second largest producer, Pennsylvania. Because of its long
history in oil and gas production, Texas sustains a large amount of conventional production, and
continues to pursue conventional reserves, both shallow and deep. Modern shale and tight oil
unconventional reserve development began in Texas in the 1990’s and recent discoveries in the
Permian Basin suggest that this will be a significant part of future exploration and production. The Oil
and Gas Division of the Railroad Commission of Texas (RRC) regulates oil and natural gas production
in the state. E&P wastes are regulated by the RRC under a memorandum of agreement with the Texas
Commission on Environmental Quality (TCEQ). The Department of Environmental Quality, Land
Protection Division is responsible for management of solid waste. NORM related to oil and natural gas
production is regulated by RRC under a memorandum of agreement with Texas Department of State
Health Services (DSHS).
Texas maintains an extensive set of regulations for oil and gas that address a wide range of
environmental issues. RRC rules (Title 16, Part 1) include 15 sections including two that address waste
management requirements (Oil and Gas Division Rules, Chapter 3, and Environmental Protection,
Chapter 4). Chapter 3.8 (Water Protection) contains most of the waste management regulations, and
Chapter 4 addresses commercial E&P waste recycling and NORM. Several chapters of the regulations
have been updated as recently as 2016; Chapter 3.8 and most of Chapter 4 were most recently updated
in 2013. Table C-1 provides a summary of the regulations identified for E&P wastes in Texas.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-2

Table C-1. Summary of Regulations for E&P Wastes in Texas
Topic Area Summary
Definitions
Section 3.8 includes 47 definitions related to waste and water protection, and more
definitions are included within other parts of the rules. The regulations define 16 different
types of pits and TRC has grouped the pit regulations by addressing nine types of pits.
Additionally, five types of commercial recycle/reuse operations (on and off lease) are
addressed in Chapter 4.
Waste Unit Location
Requirements
Regulations pertaining to siting waste management units in floodplains are dispersed in
the reserve pit section and all five sections of recycling operations regulations and
indicate that “all authorized pits shall be constructed, used, operated, and maintained at
all times outside of a 100-year flood plain.” Regulations for surface water and
groundwater are overarching and state “No person conducting activities subject to
regulation by the commission may cause or allow pollution of surface or subsurface water
in the state.” No specific criteria for siting or operation using the term “groundwater” was
found. However, throughout the Pit Permit requirements in §3.8 (Water Protection) the
director may only issue permits if "the activity does not result in waste of oil, gas, or
geothermal resources or pollution of surface or subsurface water." Siting and location
requirements related to endangered species are not specifically addressed.
The only siting requirements provided in the regulations are a 100-foot setback distance
from sensitive areas for commercial recycling plants, and a 150-foot setback from surface
water and water supply wells for on-lease commercial waste recycling. Sensitive areas are
defined as “by the presence of factors, whether one or more, that make an area vulnerable
to pollution from crude oil spills. Factors that are characteristic of sensitive areas include
the presence of shallow groundwater or pathways for communication with deeper
groundwater; proximity to surface water, including lakes, rivers, streams, dry or flowing
creeks, irrigation canals, stock tanks, and wetlands; proximity to natural wildlife refuges
or parks; or proximity to commercial or residential areas.” Minimum depth to
groundwater for waste units is not specified.
Tank Requirements
TRC regulations do not address many aspects of tanks used for waste management and
TCEQ tank regulations (§334.123. (a)(7) Exemptions for Aboveground Storage Tanks
(ASTs) exempts oil and gas tanks. General requirements are provided for protection of
birds for open-top storage tanks that are eight feet or greater in diameter and contain a
continuous or frequent surface film or accumulation of oil. These tanks must be screened,
covered or otherwise rendered harmless to birds; however, temporary, portable storage
tanks that are used to hold fluids during drilling operations, workovers, or well tests are
exempt. Recycling facilities, which may contain tanks, also require bird protections and
require design and construction of storage areas, containment dikes and processing areas
to prevent pollution of surface and subsurface water. Modular large volume tanks,
construction materials, and monitoring are not specifically addressed in the regulations.
Permits are required for removal of tank bottoms or other hydrocarbon wastes from any
producing lease tank, pipeline storage tank, or other production facility.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-3

Table C-1. Summary of Regulations for E&P Wastes in Texas
Topic Area Summary
Pit Construction and
Operation Requirements

Short term use pits including reserve pits, mud circulation pits, completion/workover pits,
basic sediment pits, flare pits, fresh makeup water pits, fresh mining water pits, non-
commercial fluid recycling pits, and water condensate pits are authorized by rule and no
permit is required when specified conditions in Rule 3.8 are met (also called permit-by-
rule). Permits are required for longer term storage pits, salt water pits and disposal pits
such as saltwater disposal pits; emergency saltwater storage pits; collecting pits;
skimming pits; drilling fluid storage pits (other than mud circulation pits); drilling, fluid
disposal pits (other than reserve pits or slush pits); washout pits; and gas plant
evaporation/retention pits. Pits associated with certain recycling facilities are included as
part of the facility permits. Storage of oil in pits of any type is prohibited.
Design and construction requirements for permit-by-rule pits are not explicitly defined
in most pit regulations. Only non-commercial fluid recycling pits include specifications.
For these pits, liner materials may vary and must have a permeability less than 1×10-7
cm/sec. For permitted pits requirements such as dike design, minimum depth to
groundwater, liner material and thickness, schedules, and fences, are specified in the
permits. In addition, skimming pits and collecting pits must be screened, covered or
otherwise rendered harmless to birds.
General freeboard and berm requirements are provided for non-commercial fluid
recycling pits stating that “All pits shall be sufficiently large to ensure adequate storage
capacity and freeboard taking into account anticipated precipitation.” and “All pits shall
be designed to prevent stormwater runoff from entering the pit. If a pit is constructed
with a dike or berm, the height, slope, and construction material of such dike or berm
shall be such that it is structurally sound and does not allow seepage.” Signs are required
for the general well location and are not pit specific.
Inspections and groundwater monitoring are required for commercial
recycle/reclamation pits, brine pits, and as specified in a permit. Permits and leak
detection/monitoring are required for brine pits only.
Discharge from pits requires a letter of request but no application or permit is necessary.
Centralized pits are not specifically addressed in the regulations, but they may fall under
non-commercial fluid recycling pits located offsite.
Pit Closure Requirements

Most drilling fluids and cuttings can be disposed in the original pit by burial. Liquids
removal is required prior to pit closure for high chloride fluids. Completion and workover
wastes (including fluids and solids) can be buried on site in their original pits, as can solids
generated from non-commercial recycling pits. The closure schedule varies depending
upon pit type, and details are provided in the regulations. Generally, drilling pits must be
backfilled and compacted within one year, and all other pits (completion, workover, basic
sediment and others) must be backfilled within 120 days.
Liners for non-commercial fluid recycling pits must be inspected annually by the operator
unless a double liner with leak detection is used. Storage areas for commercial
recycling/reclamation pits must be inspected as indicated by permit. Sampling is
necessary for stationary solid waste recycling facilities, waste separation facilities,
reclamation facilities, or as specified by permit. For wells, financial security is not pit-
specific but rather provided by the general APD bond. Financial security bonds are
required for all five categories of recycling facilities in Chapter 4.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-4

Table C-1. Summary of Regulations for E&P Wastes in Texas
Topic Area Summary
Spill Notification

Unpermitted discharge from any pit requires the operator to take any measures necessary
to stop or control the discharge and report the discharge to the district office as soon as
possible. For other waste management units (tanks) immediate notification of a fire, leak,
spill or break is required followed by a letter giving the full description of the event, and
the volume of crude oil, gas, geothermal resources, other well liquids, or associated
products lost.
Corrective Action
Response actions for crude oil and condensate releases are addressed in the regulations,
but the corrective action process for exempt wastes is not described in the regulations.
According to the Memorandum of Understanding between RRC and TCEQ, RRC is solely
responsible for the control and disposition of waste and the abatement and prevention
of pollution of surface and subsurface water in the state from activities associated with
the exploration, development, and production of oil and gas. RRC Cleanup Orders appear
to be used to identify actions and timelines for remediating releases of waste.
Off-site Landfills

Disposal of E&P waste is allowed in offsite pits and require a permit. Commercial pits
require testing of waste and groundwater monitoring wells. Disposal of exempt waste in
municipal solid waste landfills is not discussed in the regulations but appears to be
allowed with concurrence from TCEQ (TXCEQ, 2014). Use as daily cover is not specifically
addressed in the regulations.
Land Application
Land application (landfarming) of E&P waste on-lease property is allowed for low chloride
muds and cuttings and does not require a permit (considered permit-by-rule). Other than
the chloride content, there are no specific limitations/conditions for landfarming. Off-
lease application requires a disposal permit, which includes site specific
limitations/restrictions for use.
Beneficial Use
Non-commercial recycling or reuse of treated fluid is allowed and does not require a
permit. Commercial recycling facilities are subject to location and operating conditions
provided in the regulations and facility permit.
Beneficial use of basic sediment is allowed for application to lease roads, and a permit is
required for off-lease applications only. Roadspreading of brine does not appear to be
explicitly allowed under the regulations, but the RRC has flexibility to approve
applications for alternate disposal and use of brine. Disposal of oil and gas NORM waste
on roads is prohibited.
Waste Minimization/
Management

Waste minimization practices, such as closed loop drilling and mandatory recycling of
produced water are not specifically addressed in the regulations. The RRC Waste
Minimization Guide and guidance on the RRC website encourage the reduction, reuse
and recycling of wastes.
Commercial Recycling and
Reclamation Facilities

RRC Chapter 4 presents the regulations for five different types of commercial recycling
facilities including:
 On-Lease Commercial Solid E&P waste Recycling Facilities
 Off-Lease Commercial Solid E&P waste Recycling Facilities
 Stationary Commercial Solid E&P waste Recycling Facilities
 Off-Lease Commercial Recycling of Fluid
 Stationary Commercial Recycling of Fluid
Regulations for each facility type are addressed in the regulations and all require permits
and financial security. Many of the technical specifications are contained in the operating
permits, which are based on information provided during the permit application process.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-5

Table C-1. Summary of Regulations for E&P Wastes in Texas
Topic Area Summary
NORM and TENORM

Oil and gas NORM waste is regulated in Texas by RRC under memorandum of agreement
with DSHS, and such waste is addressed in the oil and gas regulations. Testing of NORM
wastes is required prior to disposal, which may include burial at generation location or
landfarming if waste does not exceed 30 pCi/g Radium-226 combined with Radium-228
or 150 pCi/g of any other NORM radionuclide. Off-site disposal and injection are also
options for NORM.

C.2. Pennsylvania
In 2016, Pennsylvania accounted for approximately 11.5% of the nation’s oil and gas production
according to data provided by the U.S. Energy Information Agency. Much of the production is from
unconventional reserves in the Marcellus (beginning around 2003), and the remaining is from
shallower conventional wells associated with oil and gas producing intervals since the mid 1800’s. In
2017, a total of 2,028 unconventional permits were issued and 203 conventional permits were issued
(PADEP, 2018). Part of Pennsylvania is underlain by the Utica Shale, which is a potential target for
future unconventional oil and gas production. The Office of Oil and Gas Management in Pennsylvania’s
Department of Environmental Protection (PADEP) regulates oil and natural gas production in the state.
The PADEP also regulates solid and hazardous wastes. NORM/TENORM is not specifically addressed
in state oil and gas regulations. Pennsylvania substantially updated its E&P regulations by adding
Chapter 78a to address unconventional wells in 2016. The new section provides more stringent
requirements for many waste management activities including pits, modular tanks and centralized pits.
Table C-2 provides a summary of the regulations identified for E&P wastes in Pennsylvania.
Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania
Topic Area Summary
Definitions

Approximately 150 definitions are provided between Chapters 78 and 78a of the
regulations; some appear in both chapters. Pits are defined generally, but specific types
are not defined or addressed in the regulations. Text in the regulations note that pits are
temporary, and pit and tank contents may include wastes generated from drilling,
altering, completing, recompleting, servicing and plugging the well including brines, drill
cuttings, drilling muds, oils, stimulation fluids, well treatment and servicing fluids,
plugging and drilling fluids.
Regulations regarding oil and gas activities distinguish the drill cutting type based on
origination, either from above the surface casing seat (uncontaminated drill cuttings,
tophole water or fresh water) or below the surface casing seat (contaminated drill cuttings
and associated fluids).

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-6

Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania
Topic Area Summary
Waste Unit Location
Requirements
Regulations regarding protection of floodplains, surface water and groundwater are
dispersed throughout the various technical regulations for pits, tanks and other activities.
An analysis of the well’s impact on endangered species is required in the permit
application and endangered species are mentioned in the pipeline planning regulation.C1
Location restrictions are provided (for example, pits shall not be located within 100 feet
of a stream, body of water or wetland, or within 200 feet of a water supply). In addition,
wastes from below the casing seat (potentially contaminated with oi and gas fluids) may
not be disposed or land applied within 200 feet of an existing building.
Tank Requirements

Regulations for tanks refer to requirements under 40 CFR Part 112. Signs are required at
tank batteries, and at least 2 feet of freeboard is necessary for all open tanks or storage
structures. While specific construction materials are not specified, the container must be
impermeable to contain the regulated substances which are used or produced during
drilling, altering, completing, recompleting, servicing and plugging the well. Modular
large volume tanks are addressed in the regulations, and those that exceed 20,000-gallon
capacity need prior Department approval. A permit is required for removal of tank
bottoms.
Tank monitoring and netting requirements are not specifically addressed in the
regulations. Open top structures are not allowed for storage of produced fluids (brine
and hydrocarbons). Because the tank rules reference 40 CFR Part 112, federal
requirements for construction and operation may apply.
Pit Construction and
Operation Requirements

Pit contents recognized in the regulations include a wide range of wastes generated from
drilling, altering, completing, recompleting, servicing and plugging the well including
brines, drill cuttings, drilling muds, oils, stimulation fluids, well treatment and servicing
fluids, plugging and drilling fluids. Pits require a permit and may not be used for
temporary storage. A distinction is made between (1) pits used for uncontaminated drill
cuttings from above the casing seat, tophole water (generated from drilling the shallow
portion of the hole) and fresh water and (2) pits used to contain drill cuttings from below
the casing seat, pollutional substances, wastes or fluids other than tophole water, fresh
water and uncontaminated drill cuttings. Pits for contaminated drill cuttings or fluids
other than tophole or fresh water have more stringent requirements, such as a synthetic
liner or an alternative material (if approved by the Department) and the bottom of the pit
shall be at least 20 inches above seasonal high groundwater table.

C1) § 78a.68. Oil and gas gathering pipelines also includes associated facilities which may consist of pigging stations, drip pits and
compressor stations which may handle or store exempt E&P wastes. The regulation requires flagging of endangered species
habitat prior to land clearing.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-7

Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)

Fencing is required for well development impoundments only and not pits specifically,
although a well development impoundment is functionally equivalent to a pit. Berm
requirements are specified for well development impoundments at unconventional wells
and produced fluids containment at conventional wells. Regulations also address signage,
inspections, temporary pit requirements, and run-on/run-off controls. Groundwater
monitoring does not appear to be required for wells or specific waste management units.
However, the regulations imply that water quality data from preconstruction monitoring
at centralized impoundments is required. State guidance notes that under PA Act 13
(2012 improvements to oil and gas laws) there is a presumption of liability for
contamination of private water supply wells within 2500 feet of oil and gas wells. While
the regulations have no requirement for pre-drill sampling, they put the onus on oil and
gas industry for groundwater monitoring at nearby water supplies. Onsite processing of
wastes at noncommercial fluid recycling pits is allowed for beneficial use only. Centralized
pits at unconventional wells require a permit.
Regulations do not address leak detection or monitoring or netting of pits.
Pit Closure Requirements

Conventional well regulations allow closure of lined pits in place and specify liquids must
be removed prior to backfilling of the pit. A permit may be required. Remaining
contaminated drill cuttings (defined as residual waste) must be encapsulated in the liner
and folded over (or an additional liner added). Regulations also require covering the
waste prior to backfilling with at least 18 inches of soil. Cuttings from unconventional
wells cannot be disposed in pits without approval of the director and in compliance with
regulations for management of residual wastes.
Pits containing production fluids must be closed within 9 months after completion of
drilling. Pits used during servicing, plugging and recompleting a well shall be closed
within 90 days of construction. Regulations state that inspections of wells with onsite
brine disposal or residual waste are intended to be inspected at least once per year. Bonds
are required for wells, but there are no financial security requirements for pits or other
waste management units.
Spill Notification

The owner/operator shall notify the appropriate regional office of the Department as
soon as practicable (but no later than 2 hours) after detecting or discovering a reportable
release of brine on or into the ground at the well site. A reportable release of brine is
defined as “spilling, leaking, emitting, discharging, escaping or disposing of one of the
following: (i) More than 5 gallons of brine within a 24-hour period on or into the
ground at the well site where the total dissolved solids concentration of the brine is equal
or greater than 10,000 mg/l. (ii) More than 15 gallons of brine within a 24-hour period on
or into the ground at the well site where the total dissolved solids concentration of the
brine is less than 10,000 mg/l.”
Unconventional wells: Notification is required as soon as practicable but no later than 2
hours after discovering the following spills/releases at unconventional well sites: (1) spills
or releases of a regulated substance causing or threatening pollutions of the
Commonwealth or (2) spills or releases of 5 gallons or more of a regulated substance
over a 24-hour period that is not completely contained by secondary containment. The
operator or other responsible party shall take necessary interim corrective actions,
identify and sample water supplies that have been polluted or threatened. Temporary
emergency storage or transportation methods may be approved by the Department.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-8

Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania
Topic Area Summary
Corrective Action
“Upon the occurrence of any release, the owner or operator shall take necessary
corrective actions to: (1) Prevent the substance from reaching the waters of this
Commonwealth. (2) Recover or remove the substance which was released. (3) Dispose of
the substance in accordance with this subchapter or as approved by the Department.”
(78.66 - https://www.pacode.com/secure/data/025/chapter78/025_0078.pdf)
Unconventional wells: “Remediation of an area polluted by a spill or release is required.
The operator or other responsible party shall remediate a release in accordance with the
following: (1) Spills or releases to the ground of less than 42 gallons at a well site that do
not pollute or threaten to pollute waters of the Commonwealth may be remediated by
removing the soil visibly impacted by the spill or release and properly managing the
impacted soil in accordance with the Department’s waste management regulations. The
operator or responsible party shall notify the Department of its intent to remediate a spill
or release in accordance with this paragraph at the time the report of the spill or release
is made. (2) For spills or releases to the ground of greater than or equal to 42 gallons or
that pollute or threaten to pollute waters of the Commonwealth, the
operator or other responsible person must demonstrate attainment of one or more of
the standards established by Act 2 and Chapter 250 (relating to administration of Land
Recycling Program).”
(78a.66 - https://www.pacode.com/secure/data/025/chapter78a/025_0078a.pdf)
Off-site Landfills
E&P waste disposal is allowed at municipal solid waste landfills that are permitted to
accept the waste. Testing of waste and its use as daily cover are not specifically addressed
in the regulations.
Land Application
Drill cuttings may be land applied, however, specifications vary depending on whether
the materials originate from above or below the casing seat, and a permit is required.
Requirements for land application are detailed and address contaminants, distance from
sensitive receptors, soil thickness, percolation controls (frozen ground and free liquid
content), loading and application rate, and revegetation requirements. Tophole water or
water in a pit as a result of precipitation may not be land applied unless specific water
quality requirements are met.
Beneficial Use
Regulations state that production brines from unconventional wells may not be used for
dust suppression, road stabilization, pre-wetting, anti-icing and de-icing. Conventional
well regulations are moot on the application of brines to roads (roadspreading) but a
2011 PA DEP fact sheet states “DEP considers roadspreading of brine for dust control and
road stabilization to be a beneficial use of the brine.” And further explains that brines
from shale gas formations are not allowed to be used. The fact sheet outlines seven
components of a plan that must be addressed prior to receiving a permit for beneficial
use. Road spreading is strictly controlled and subject to 14 operating requirements
relating to rate and frequency, sources of brine, chemical composition and presence of
contaminants, proximity to water sources and sensitive receptors, spreading equipment,
road conditions and monthly reporting.
Waste Minimization/
Management
Regulations do not specify closed loop drilling, but pits are not allowed for
unconventional well drilling, therefore it assumed that closed loop or pitiless drilling is
required. Produced water recycling is not required.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities for water or cuttings are
not specifically addressed in these regulations.
NORM and TENORM State regulations do not address NORM/TENORM. Radiation testing is required for
disposal at off-site municipal landfills but not for NORM/TENORM specifically.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-9

C.3. Alaska
Alaska accounted for approximately 8.4% of the nation’s oil and gas production in 2016, all from
conventional resources, according to the U.S. Energy Information Agency. The Alaska Oil and Gas
Conservation Commission within the Department of Administration regulates oil and gas production
and facilities. Solid and hazardous waste are regulated by the Alaska Department of Environmental
Conservation, Division of Environmental Health. NORM/TENORM is not specifically addressed in
state oil and gas regulations. Many oil and gas and solid waste regulations were updated in 2017, in
particular regulations regarding drilling waste disposal. Table C-3 provides a summary of the
regulations identified for E&P wastes in Alaska.
Table C-3. Summary of Regulations for E&P Wastes in Alaska
Topic Area Summary
Definitions
E&P regulations contain 77 definitions, but few are related to the waste management
processes. Pits are not included in the definitions and only reserve pits are mentioned by
name/use in these regulations.
Waste Unit Location
Requirements
There are no specific siting or location requirements for waste management facilities
associated with drilling, completion and production facilities. Solid waste regulations
related to siting and locations are dispersed throughout the rules for drilling waste
landfills and include general operating requirements to not impact surface water or
groundwater. Endangered species are not specifically addressed in these regulations.
The only setback specified is for a new landfill or expansion of an existing landfill that
may not be constructed within 500 feet of a drinking water supply well.
Tank Requirements
Regulations refer to API standards for construction, including steel and fiberglass. Tank
monitoring requires an external gage or catchment/sump. No other tank requirements
are included in these regulations; modular large volume tanks, netting, tank monitoring
and tank bottom removal are not specifically addressed.
Pit Construction and
Operation Requirements
All drilling pits (including completion and production pits) are considered drilling waste
temporary storage facilities and are included under the solid waste regulations. Permits
are not required for pits, but a drilling waste storage plan is necessary as part of the well
permitting process, and requires information on the location, construction specifications
operational practices, and ultimate disposal location of the wastes. Reserve pits for the
confinement of drilling fluids and cuttings are the only type of pit mentioned by
name/use. Reserve pits have few requirements other than to be properly sized and
impervious. Liners for temporary pits are required and must be made of flexible
geomembrane (30 or 60 mils thick) that is compatible with petroleum. Precipitation
should be included in the design to ensure that a minimum freeboard of 2 feet is
maintained, and confinement dikes should be avoided or kept to a minimum; pit
construction must ensure integrity. Run-on/run-off control measures are not specified
for pits but indicate that runoff from landfills should not be polluted run-off water. Signs
are required for wells and drill waste landfills but not pits specifically.
Pit requirements are not provided for leak detection/monitoring, fencing, netting, depth
to groundwater, groundwater monitoring, inspection, non-commercial fluid recycling pits
or centralized pits.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-10

Table C-3. Summary of Regulations for E&P Wastes in Alaska
Topic Area Summary
Pit Closure Requirements
Pit closure consists of a general requirement that upon completion the operator shall
proceed with diligence to leave the reserve pit in a condition that does not constitute a
hazard to freshwater. A visual site inspection must be conducted to verify that all drilling
waste has been removed. Financial security for pits is included in the general well
bonding.
Spill Notification Spill notification is not specifically addressed in the state regulations.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
Drilling waste monofills are specified in the solid waste regulations. General requirements
allow for only RCRA-exempt wastes (Footnote: the citation date “40 C.F.R. 261.4(b)(5),
revised as of July I, 1998” appears to be incorrect). Regulations specify design standards
including liners, freeboard, protection of surface water and groundwater, and maintain
integrity. Visual and groundwater monitoring is required. Drilling waste landfills in
permafrost areas must be designed and monitored to protect the permafrost. Closure of
the landfill requires removal of liquids, capping and post closure care requirements (deed
notice and visual monitoring for 5 years).
Testing and use of waste as a daily cover in municipal solid waste landfills are not
specifically addressed.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use of drill cuttings may be allowed by special request/approval.
Waste Minimization/
Management
Waste minimization and management activities, such as closed loop drilling and
produced water recycling, are not specifically addressed in these regulations.
Commercial recycling and
reclamation facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in the state regulations.
NORM and TENORM NORM and TENORM are not specifically addressed in the state regulations.

C.4. Oklahoma
In 2016, Oklahoma accounted for approximately 7.3% of the nation’s oil and gas production according
to the U.S. Energy Information Agency. Oil and gas production come from conventional resources
(shallow vertical wells) that have been producing since the early 1900’s and several recent
unconventional resources play across the state.C2 In 2016, about 20% of the completed wells were from
conventional reservoirs. The Oil and Gas Division within the Oklahoma Corporation Commission
regulates oil and natural gas production in the state. The Department of Environmental Quality, Land
Protection Division is responsible for management of solid waste. NORM/TENORM is not specifically
addressed in state oil and gas regulations.

C2) A play is an area in which hydrocarbon accumulations or prospects of a given geologic type occur. A play may comprise many
different fields or may be a continuous accumulation of oil and gas across a large area. Examples: Marcellus, Utica, Mississippi
Lime, Eagle ford and others.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-11

Oil and Gas Conservation regulations (Title 165, Chapter 10) include 19 chapters and are regularly
updated. Sections of the Drilling regulations (Chapter 3) Pollution Abatement regulations (Chapter 7),
Commercial Recycling (Chapter 8) and Commercial Disposal (Chapter 9) regulations have been
updated in 2013, 2015 and 2017. Regulations provide specifications and requirements, and also allow
the OCD to approve alternative approaches by operators. Table C-4 provides a summary of the
regulations identified for E&P wastes in Oklahoma.
Table C-4. Summary of Regulations for E&P Wastes in Oklahoma
Topic Area Summary
Definitions
Approximately 130 definitions are provided in the general provisions for oil and gas
operations (Title 165, Chapter 10). Multiple pit types are defined, including commercial
pits, completion/fracture/workover pits, emergency pits, noncommercial pits, off-site
reserve pits, recycling/reuse pits, remediation pits and reserve/circulation pits. Other
terms including “truck wash pit” and “deleterious substances” are defined.C3 Land farming
is referred to as soil farming in the regulations.
Waste Unit Location
Requirements
Regulations pertaining to floodplains, surface water and groundwater are dispersed
throughout the drilling and pollution abatement sections, while regulations for
endangered species are overarching and only included as notices to operators that they
must comply with federal statutes, such as the Bald Eagle Protection Act and the
Migratory Bird Treaty Act.
Siting requirements are provided for noncommercial pits, commercial pits, and
commercial facilities, including landfarming and recycling facilities. Requirements vary
from general (pits and facilities must be constructed such that contents will not be
harmful to groundwater, surface water, soils, plants or animals) to specific (for example,
noncommercial pits, commercial pits, and commercial landfarming or recycling facilities
may not be constructed within a 100-year floodplain). Residential setback is not specified
in these regulations. Minimum depth to groundwater requirements are 25 feet for pits
and other waste facilities.
Tank Requirements
General requirements are provided for tanks. Examples include “protection of migratory
birds” for open tanks, and they should be “constructed and maintained so as to prevent
pollution.” Detailed specifications are not provided. Crude oil tanks (which may include
tank bottoms) also fall under general requirements such as “Oil storage tanks shall be
constructed so as to prevent leakage. Dikes or retaining walls, where necessary, shall be
constructed, based on tank capacity and throughput, so as to prevent oil or deleterious
substances from causing pollution and to ensure public safety.”
While tank bottom removal permits are not required for tanks managed by operators,
they are required for commercial tank bottom reclamation facilities.
Modular large volume tanks, tank berms and containment, and monitoring and are not
specifically addressed in the regulations.

C3) Deleterious substance is a key waste term in the Oklahoma regulations covering a wide range of materials and wastes. It includes
any chemical, salt water, oil field brine, waste oil, waste emulsified oil, basic sediment, mud, or injurious substance produced or
used in the drilling, development, production, transportation, refining, and processing of oil, gas and/or brine mining.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-12

Table C-4. Summary of Regulations for E&P Wastes in Oklahoma
Topic Area Summary
Pit Construction and
Operation Requirements
Construction and operation requirements are provided for noncommercial pits, which
include completion, fracture, and workover pits, emergency pits, recycling/reuse pits, spill
containment pit, remediation pits and reserve/circulation pits. Permits are required for
such pits.
Liner requirements vary for noncommercial pits, including reserve/circulation and/or
completion/fracture/workover pits. The requirements are determined by the
Commission’s Technical Services Department and depend upon soil and fluid
characteristics for each well site. The site will be classified to require one of five categories
of containment (liner systems) ranging from unlined to geomembrane liners. Details for
each category is provided in the regulations. In addition, emergency pits are not required
to be lined, and basic sediment pits must have a geomembrane liner.
Fencing is required for commercial pits and noncommercial brine disposal and flowback
water pits but are not required for reserve and circulation pits. Requirements for netting
refer to federal statutes.
Freeboard requirements range from 6 inches to 3 feet depending on the pit construction
and contents, and pits constructed to not receive runoff water. Requirements for
minimum depth to groundwater, berm construction, and signage are also provided.
Offsite reserve pits and recycling require signs, but pits associated with well sites only
require general lease signs. Flowback water pits with capacity of 50,000 bbl. (either onsite
or offsite) require signage.
Groundwater monitoring is necessary for brine disposal well pits and flowback pits with
capacities greater than 50,000 barrels. Inspections are only specified for flowback water
pits. OCD is required to inspect all reserve and circulation pits in the special rule areas of
Atoka, Pittsburg and Coal counties
Discharge permits are required for produced water and hydrostatic test/storm water with
elevated constituents.
Saltwater disposal pits and flowback pits are defined as temporary storage and require
permits. Non-commercial fluid recycling pits and centralized pits (only for recycling and
reuse of drilling mud) are also addressed in the regulations.
Pit Closure Requirements
Liquids removal is required prior to pit closure, and multiple options for solids are allowed
including on site burial with or without stabilization and offsite disposal. Closure in place
requires minimum of three feet of soil cover and erosion control. The closure schedule is
provided in the regulations and depends upon the pit category or type/contents. Most
pits, including all reserve/circulation and flowback water pits must be closed within three
to 12 months, but flare and spill pits must be closed within 30 days, and basic sediment
pits must be closed within 60 days. Inspection, sampling and financial security are all
required for closure of pits.
Spill Notification
Nonpermitted discharges require verbal reporting within 24 hours of discovery of (i) Any
non-permitted discharge of deleterious substances of ten barrels or more (single event)
to the surface; or (ii) Any discharge of a deleterious substance, regardless of quantity, to
the waters of the State. A written report shall be filed within 10 business days.
Corrective Action
The Pollution Abatement regulations refer to cleanup practices and requirements
addressed in the general practices appearing in the Oil and Gas Conservation Division's
Guardian Guidance document. The guidance is a step by step methodology containing
numerical and risk based cleanup approaches.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-13

Table C-4. Summary of Regulations for E&P Wastes in Oklahoma
Topic Area Summary
Off-site Landfills
Disposal of E&P waste at offsite landfills is not specified in the regulations but rather
based on Department of Environmental Quality approval or landfill permit requirements,
and testing is required prior to disposal.
Use of waste as daily cover is not specifically addressed in the regulations.
Land Application
Water-based fluids and/or drill cutting from earthen pits and tanks may be land applied
with a permit. Land restrictions (such as a maximum slope of 8% and minimum depth to
bedrock of 20 inches) are provided in the extensive set of regulations. Sampling
requirements and limitations/conditions for application are also included.
Details and conditions for commercial soil farming are also included.
Beneficial Use
Beneficial use of brine (reuse and recycling) is allowed but details are not included in
regulations.
Roadspreading is not allowed. However, the regulations allow waste oil, residue and
crude oil contaminated soil to be applied to lease roads and county roads with a permit.
According to the table of allowable uses, drill cuttings from freshwater and oil-based
muds can be applied to lease roads also.
Waste Minimization/
Management
Waste minimization practices, such as closed loop drilling and recycling of produced
water, are not specifically addressed in the regulations.
Commercial Recycling and
Reclamation Facilities
Subchapter 9 of Title 165, Chapter 10 addresses commercial disposal facilities, including
pits, soil farming, disposal well surface facilities, and recycling facilities. Detailed
requirements, including permitting, construction, financial security, and
sampling/monitoring are provided for each commercial facility type.
NORM and TENORM NORM and TENORM are not specifically addressed in state regulations.

C.5. North Dakota
In 2016, North Dakota accounted for approximately 6% of the U.S. oil and gas production as indicated
by U.S. Energy Information Agency data. E&P wastes generated in North Dakota are regulated by the
Industrial Commission of North Dakota, Division of Oil and Gas. Off-site waste disposal and TENORM
are regulated under the North Dakota Department of Health, Solid Waste Management and Land
Protection. Oil and gas regulations are amended frequently, including several updates in 2012, 2014,
and 2016, which addressed fencing, drilling pits and reserve pits, in addition to other topics. Updated
solid waste TENORM rules became effective in 2015. Table C-5 provides a summary of the regulations
identified for E&P wastes in North Dakota.
Table C-5. Summary of Regulations for E&P Wastes in North Dakota
Topic Area Summary
Definitions
The General Oil and Gas Rules and Regulations (Chapter 43-02-03) provide 52 general
definitions including “occupied dwelling” (lived in by a person at least six months in a
calendar year). The term “saltwater handling facility” is a broad definition that appears to
include any container or site used for handling storage or disposal throughout the
drilling, completion and production phases. Definitions of pit types defined in the
regulations include reserve pit, earthen pits/open receptacles, and drilling pits.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-14

Table C-5. Summary of Regulations for E&P Wastes in North Dakota
Topic Area Summary
Waste Unit Location
Requirements
General location standards are provided for solid waste facilities, not E&P waste facilities
specifically. For example, no solid waste management facility may be located in areas
which result in impacts to human health or environmental resources or in an area which
is unsuitable because of reasons of topography, geology, hydrology, or soils. Solid waste
regulations contain more specific requirements; for example, solid waste facilities are not
allowed within a one hundred-year floodplain or in areas designated as critical habitats
for endangered or threatened species of plant, fish, or wildlife.
Oil and gas regulations provide general requirements for siting. Drilling pits shall not be
located in, or hazardously near, bodies of water. Saltwater handling facilities and treating
plants shall be sited in such a fashion that they are not located in a geologically or
hydrologically sensitive area. There are no specific setback requirements for E&P waste
management facilities.
Tank Requirements
Produced water tanks and saltwater handling facilities require dikes when deemed
necessary by the director. Dikes must be constructed of sufficiently impermeable material
to provide emergency containment.
Tank monitoring and netting for open tanks are not specifically addressed. The director
may permit portable-collapsible receptacles used solely for storage of fluids used in
completion and well servicing operations, although no flowback fluids may be allowed.
Pit Construction and
Operation Requirements
Regulations in North Dakota cover and require permits for the following pit types: reserve
pit, earthen pit/open receptacle, and drilling pits. Unlined earthen pits for saltwater,
drilling mud, crude oil, waste oil, or other wastes are prohibited, except in an emergency
and upon approval by the director. The director may permit pits or receptacles used solely
for the purpose of flaring casinghead gas. Pits for treatment plants and saltwater facilities
are prohibited unless authorized by an appropriate regulatory agency. Regulations allow
for less stringent pit and disposal requirements for shallow wells using freshwater muds.
Limited details are provided for pit construction and operation. Liners are mentioned but
no details are included (for example, “A lined earthen pit or open receptacle may be
temporarily used to retain oil, water, cement, solids, or fluids generated in well plugging
operations…Freshwater pits shall be lined and no pit constructed for this purpose shall
be wholly or partially constructed in fill dirt unless approved by the director”). Fencing is
required for open pits and ponds that contain saltwater or oil and is not required for
drilling or reserve pits used solely for drilling, completing, recompleting or plugging
except after 90 days or unless indicated by the director. All pits and ponds that contain
oil must be fenced, screened and netted.
Berm specifications are general for drilling pits (“shall be diked in a manner to prevent
surface water from running into the pit”) while berms for saltwater handling facilities are
more specific (for example, height requirements and must be constructed of “sufficiently
impermeable material”). At saltwater handling facilities and treating plants, waste,
recovered solids, and fluids must be stored and handled in such a manner to prevent
runoff or migration offsite.
Signage is required for freshwater pits, as well as portable-collapsible receptacles. Drilling
pits require inspection by an authorized representative of the director prior to lining and
use. Inspection was not noted for other types of pits. Monitoring plans and leak detection,
which may include groundwater monitoring, are necessary for all buried and partially
buried structures at treatment plant facilities.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-15

Table C-5. Summary of Regulations for E&P Wastes in North Dakota
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Regulated pits may be used temporarily to (1) retain oil, water, cement, solids or fluids
generated during well plugging operations containment, or (2) contain incidental fluids
such as trench water and rig wash. Flare pits are considered temporary. Noncommercial
fluid recycling pits are not specifically prohibited or allowed, however saltwater handling
and disposal operations or fluid and tank bottom treatment at the well site which typically
recover skim oil from their operations, is permitted. Central production facilities and
centralized tank batteries are discussed but centralized pits are not specifically addressed.
Freeboard requirements, minimum depth to groundwater, and discharge permits are not
specifically addressed in the regulations.
Pit Closure Requirements
Liquids removal is required for closure of drilling, reserve and temporary pits. The
contents of an earthen pit or receptacle must be removed within seventy-two hours after
operations have ceased and must be disposed of at an authorized facility. Drilling waste
in reserve and drilling pits should be encapsulated in the pit and covered with at least
four feet [1.22 meters] of backfill and topsoil and surface sloped, when practicable, to
promote surface drainage away from the reclaimed pit area.
Pits shall be reclaimed within 30 days after operations have ceased (earthen pit) or within
30 days after the drilling of a well or expiration of a drilling permit (drilling pit). Reserve
pits shall be closed within a reasonable timeframe but not more than one year after the
completion of a shallow well, or prior to drilling below the surface casing shoe on any
other well.
Prior to reclaiming a drilling pit, the operator or the operator's agent shall obtain verbal
approval from the director of a pit reclamation plan. Financial security for pits is not
required but is included as a part of the overall well permit bond.
Spill Notification
The operators or responsible parties shall verbally notify the director immediately and
follow up utilizing the online initial notification report within twenty-four hours after
discovery of any fire, leak, spill, blowout, or release of fluid. The commission, however,
may impose more stringent spill reporting requirements if warranted by proximity to
sensitive areas, past spill performance, or careless operating practices as determined by
the director.
Corrective Action
For spill cleanup, discharged fluids must be properly removed and may not be allowed
to remain standing within or outside of diked areas. Operators and responsible parties
must respond with appropriate resources to contain and clean up spills.
Off-site Landfills
North Dakota Administrative Code Section 43-02-03-19.2 states in part that all waste
material associated with exploration or production of oil and gas must be properly
disposed of in an authorized facility in accord with all applicable local, state, and federal
laws and regulations. This includes filter socks and other filter media but does not require
the offsite disposal of drilling mud from shallow wells or drill cuttings associated with the
drilling of a well. Effective June 1, 2014, a container must be maintained on each well
drilled in North Dakota to store filters until they can be properly disposed of in an
authorized facility.
Testing of waste prior to disposal and use of E&P waste as daily cover are not specifically
addressed in the regulations.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in the
state regulations.

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Appendix C: State Programs C-16

Table C-5. Summary of Regulations for E&P Wastes in North Dakota
Topic Area Summary
Commercial Recycling and
Reclamation Facilities
Saltwater handling facilities and treating plants are regulated, and a bond is required for
these facilities. The operator of a saltwater handling facility [or treating plant] shall
provide continuing surveillance and conduct such monitoring and sampling as the
commission may require. An offsite reclamation manifest is also required.
“’Treating plant’ means any plant permanently constructed or portable used for the
purpose of wholly or partially reclaiming, treating, processing, or recycling tank bottoms,
waste oils, drilling mud, waste from drilling operations, produced water, and other wastes
related to crude oil and natural gas exploration and production. This is not to be
construed as to include saltwater handling and disposal operations which typically
recover skim oil from their operations, treating mud or cuttings at a well site during
drilling operations, or treating flowback water during completion operations at a well
site.”
“’Saltwater handling facility’ means and includes any container and site used for the
handling, storage, disposal of substances obtained, or used, in connection with oil and
gas exploration, development, and production and can be a stand-alone site or an
appurtenance to a well or treating plant.”
NORM and TENORM
Disposal of TENORM is allowed at a licensed facility, and storage requirements are
provided. Limitations include (1) TENORM waste up to, but not exceeding 50.0 picocuries
per gram of Radium-226 plus Radium-228, and (2) equipment contaminated with
TENORM which does not exceed a maximum exposure level of one hundred
microroentgen per hour, including background radiation.
Landfill requirements for TENORM disposal include a composite liner (at least three feet
[91.4 centimeters] of recompacted clay with a hydraulic conductivity not to exceed 1 x
10-7 centimeters per second overlain with at least a sixty mil flexible membrane liner), and
at least one-foot of non-TENORM waste or daily cover material by the end of each
operating day (or once every 24-hour period for continuous operations). TENORM waste
must be buried at least 10 feet below the surface of the final cover. Additional cover
thickness may be required depending on the slope of the landfill.
The leachate collection system and groundwater monitoring network shall be analyzed
for background concentration of radionuclide parameters prior to receipt of any TENORM
waste. Leachate shall be analyzed for radionuclides at the same frequency as groundwater
samples are collected. If radionuclides are detected in leachate at a concentration greater
than the concentrations listed below, then the groundwater monitoring network must
begin analysis for radionuclide parameters:
- Radon: 4,000 picocuries per liter (pCi/L)
- Combined Radium-226 and Radium-228: 5 pCi/L
- Alpha particle activity (excluding radon and uranium): 15 pCi/L
- Uranium: 30 micrograms per liter (ug/L).

C.6. Colorado
According to data from the U.S. Energy Information Agency, in 2016, Colorado accounted for 5.1% of
the U.S. oil and gas production from conventional and unconventional resources. Oil and gas wastes in
Colorado is regulated by the Oil and Gas Conservation Commission under the Department of Natural
Resources. Off-site waste disposal and TENORM are regulated by the Colorado Department of Public
Health and Environment. Numerous sections of the Colorado oil and gas regulations were revised in

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-17

2015 to address practices in unconventional resource exploration and production. Additional updates
were made in 2016. Table C-6 provides a summary of the regulations identified for E&P wastes in
Colorado.
Table C-6. Summary of Regulations for E&P Wastes in Colorado
Topic Area Summary
Definitions
Section 100 of the Colorado Oil and Gas Code provides over 180 definitions including
definitions for 15 pit types: drilling pits (includes ancillary pits, completion pits, flowback
pits, and reserve pits), production pits (includes skimming/settling pits, produced water
pits, percolation pits and evaporation pits) special purpose pits (includes blowdown, flare,
emergency, basic sediment/tank bottom, workover and plugging pits) and reserve pits.
The definition of exploration and production waste cites the RCRA exemption and
provides additional clarification that wastes derived from gas plants along feeder lines,
regardless of change in gas custody, are included in the definition. The regulations define
a designated setback zone which incorporates definitions for two different setback zones
(exclusion and buffer), and urban mitigation areas where additional regulations may
apply.
Waste Unit Location
Requirements
Colorado setback requirements for well and production facilities vary depending on
activity and structure types. For example, the setback is 350 feet for designated outside
activity areas and 1,000 feet for high occupancy building units. These requirements may
be less restrictive with a mitigation plan. Production pits, special purpose pits (other than
emergency pits), and flowback pits containing E&P waste shall not be allowed within a
defined Floodplain, unless approved by the director.
In addition, the operator must determine whether the proposed oil and gas location falls
within Sensitive Wildlife Habitat or a Restricted Surface Occupancy area (definitions
provided in regulations). A consultation with Colorado Parks and Wildlife is then required.
Minimum depth to groundwater for pits is not specified.
Tank Requirements
Tank construction and operation regulations provide general requirements. For example,
buried or partially buried tanks, vessels, or structures used for storage of E&P waste shall
be properly designed, constructed, installed, and operated in a manner to contain
materials safely. A synthetic or engineered liner shall be placed directly beneath. Such
vessels shall be tested for leaks after installation and maintained, repaired, or replaced to
prevent spills or releases of waste. There are special requirements for setback locations.
Tank berms and containment structures must be sufficiently impervious and are required
for all tanks containing oil, condensate, or produced water with greater than 3,500
milligrams per liter (mg/l) total dissolved solids (TDS). Recent regulations specify that
containment berms around all tanks must be constructed of steel rings or another
engineered technology. Requirements are not provided for modular large volume tanks
or netting of open tanks.
Tank bottoms may be addressed by disposal at a commercial solid waste disposal facility,
treatment at a centralized E&P waste management facility, injection into a permitted
Class II injection well, or by an alternate method approved by the director.
Pit Construction and
Operation Requirements
Permits are required for pits covered by these regulations: drilling pits, ancillary pits,
completion pits, flowback pits, reserve pits, production pits, skimming/settling pits,
produced water pits, percolation pits and evaporation pits.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-18

Table C-6. Summary of Regulations for E&P Wastes in Colorado
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Pits are not allowed within the Buffer Zone Setback (1,000 feet), except fresh water
storage pits, reserve pits to drill surface casing, and emergency pits. In addition, unlined
pits cannot be constructed on fill material or in areas where pathways for communication
with ground water or surface water are likely to exist.
Liners are required for certain pit types or waste characteristics (details are provided in
the regulations). In Sensitive Areas, the director may require a leak detection system for
the pit or other equivalent protective measures, that may include increased record-
keeping requirements, monitoring systems, and underlying gravel fill sumps and lateral
systems. In making such determination, the director shall consider the surface and
subsurface geology, the use and quality of potentially-affected ground water, the quality
of the produced water, the hydraulic conductivity of the surrounding soils, the depth to
ground water, the distance to surface water and water wells, and the type of liner. In
addition, pit level indicators shall be used within Designated Setback Locations.
Pits must be constructed, monitored, and operated to provide for a minimum of two (2)
feet of freeboard at all times. Netting and fencing requirements appear to be a site
specific decision by the operator (and approved by the director), as follows: appropriate
netting or fencing shall be used where necessary to protect public health, safety and
welfare or to prevent significant adverse environmental impacts resulting from access to
a pit by wildlife, migratory birds, domestic animals, or members of the general public.”
Well sites constructed within Designated Setback Locations must be adequately fenced
to restrict access by unauthorized persons.
Baseline groundwater sampling is required for new wells (not specific waste units), and
signage is required for wells, batteries, centralized E&P waste management facilities and
tanks, but neither is indicated for tanks specifically. Discharge permits are required for
produced water discharging into Colorado state waters.
Produced water, emergency and flare pits are identified as temporary, but requirements
are not provided.
Non-commercial fluid recycling pits are addressed as multi-well pits. Permitted
centralized pits are allowed for the treatment, disposal, recycling or beneficial reuse of
E&P waste. This rule applies only to non-commercial facilities. Centralized facilities may
include components such as land treatment or land application sites, pits, and recycling
equipment.
Requirements are not specified for minimum depth to groundwater, berm construction,
run-on and run-off controls, or inspections.
Pit Closure Requirements
Removal of liquids and solids is required prior to pit closure. While a specific schedule is
not provided for pits, general reclamation for wells is within 3 months on crop land and
12 months on non-crop land. Inspection is required for general site reclamation (not pits
specifically). Sampling is necessary to ensure that remaining soil and groundwater
concentrations meet specified values (found in Table 910-1). Financial security for pits is
not required separately but is included as a part of the overall well permit bond.
Spill Notification Notification of spills is required within 24 hours if certain criteria are met.
Corrective Action
A Site Investigation and Remediation Workplan (Form 27) may be required when
threatened or actual significant adverse environmental impacts on any air, water, soil or
other environmental resource from a spill/release exist or when necessary to ensure
compliance with the concentration levels in Table 910-1 with consideration to Colorado
Water Quality Control Commission (WQCC) ground water standards and classifications.
Such spills/releases shall be remediated in accordance with oil and gas regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-19

Table C-6. Summary of Regulations for E&P Wastes in Colorado
Topic Area Summary
Off-site Landfills
Waste disposal at off-site facilities is allowed for produced water (permitted commercial
facilities) and drilling fluids and oily waste (commercial solid waste facilities). Other waste
such as workover fluids, tank bottoms, pigging wastes from gathering and flow lines, and
natural gas gathering, processing, and storage wastes may be addressed by disposal at a
commercial solid waste disposal facility, treatment at a centralized E&P waste
management facility, injection into a permitted Class II injection well, or by an alternate
method approved by the director.
Land Application
Land application of some E&P waste is allowed in Colorado. Water/bentonite-based
muds do not require a permit and may be used for lease road and site construction (other
uses require approval), or land treatment/application at a centralized E&P waste
management facility.
Water-based bentonitic drilling fluids may be applied at a centralized E&P waste
management facility at an average thickness of no more than three (3) inches prior to
incorporation. The drilling fluids must be applied to prevent ponding or erosion and
incorporated as a beneficial amendment into the native soils within ten (10) days of
application and resulting concentrations shall not exceed those in Table 910-1. Director
approval is not required when such drilling fluids are used a soil amendment.
Oily waste includes those materials containing crude oil, condensate or other E&P waste,
such as soil, frac sand, drilling fluids, and pit sludge that contain hydrocarbons. Land
treatment of oily waste is allowed onsite or at centralized E&P waste management
permitted facilities. Requirements include removal of free oil from the oily waste prior to
land treatment, no pooling, ponding, or runoff, and no contamination of storm water
runoff, ground water, or surface water. Treatment by disking, tilling, aerating, or addition
of nutrients, microbes, water or other amendments, is required to enhance
biodegradation. Land-treated oily waste incorporated in place or beneficially reused must
be in compliance with the concentrations in Table 910-1.
Beneficial Use
Beneficial use of E&P waste in Colorado includes spreading produced water (with less
than 3,500 mg/L TDS) on lease roads outside sensitive areas, when authorized by the
surface owner and in accordance with an approved waste management plan (per Rule
907.a(3)). Such road spreading shall not impact waters of the state, shall not result in
pooling or runoff, and the adjacent soils shall meet the concentration levels in Table 910-
1. Use of flowback fluids is not allowed for dust suppression.
In addition, to encourage and promote waste minimization, operators may propose plans
for managing E&P waste through beneficial use, reuse, and recycling by submitting a
written management plan to the director for approval on a Sundry Notice. Such plans
shall describe, at a minimum, the type(s) of waste, the proposed use of the waste, method
of waste treatment, product quality assurance, and shall include a copy of any certification
or authorization that may be required by other laws and regulations. The director may
require additional information.
Waste Minimization/
Management
Closed loop drilling systems are required within the Buffer Zone Setback.
Waste minimization is considered a best management practice and encouraged, as noted
above.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-20

Table C-6. Summary of Regulations for E&P Wastes in Colorado
Topic Area Summary
Commercial Recycling and
Reclamation Facilities
Produced water may be disposed at permitted commercial facilities.
No person shall accept water produced from oil and gas operations, or other oil field
waste for disposal in a commercial disposal facility, without first obtaining a Certificate of
Designation from the County in which such facility is located, in accordance with the
regulations pertaining to solid waste disposal sites and facilities as promulgated by the
Colorado Department of Public Health and Environment.
Financial security, offsite manifests and monitoring/testing during commercial recycling
operation are not specifically addressed in these regulations.
NORM and TENORM
The Colorado Department of Public Health and Environment has authority under
numerous Colorado statutes and regulations that are relevant to the control and
disposition of TENORM. Interim Policy and Guidance issued in 2007 clearly describes
disposal options and locations for oil and gas-related TENORM. Testing is required for
each shipment prior to transport. TENORM disposal is allowed, and limitations vary with
the type of facility. One hazardous waste landfill in Colorado can accept up to 400 pCi/g
Ra-226 and 2,000 pCi/g total activity, with a constraint on source material limits for
uranium and thorium. Three similar facilities exist in other states. Municipal solid waste
landfill limitations include 3 pCi radon, 30 pCi uranium, and 3 pCi thorium.
Action/Management Plans and storage requirements are not specifically addressed in the
interim policy.

C.7. Wyoming
In 2016, Wyoming accounted for approximately 4.9% of the nation’s oil and gas production according
to the U.S. Energy Information Agency. E&P wastes generated in Wyoming are regulated by the
Wyoming Oil and Gas Conservation Commission. Regulations regarding wastes disposed offsite are not
specifically addressed in the regulations. NORM and TENORM wastes are regulated under the
Wyoming Department of Environmental Quality Solid and Hazardous Waste Division. Several areas of
the regulations, including new groundwater monitoring requirements, were updated in 2015 and 2016.
Table C-7 provides a summary of the regulations identified for E&P wastes in Wyoming.
Table C-7. Summary of Regulations for E&P Wastes in Wyoming
Topic Area Summary
Definitions
The following pits are subject to this regulation:
(i) Reserve pits on the drilling location;
(ii) Reserve pits off the location within a lease, unit or communitized area permitted by
Owner or unit Operator drilling the well;
(iii) Produced water retention pits, skim pits, and emergency production pits including
the following:
(A) Pits associated with approved disposal wells which act as fluid storage, filtering
or settling ponds prior to underground disposal in a Class II well;
(B) Pits constructed for disposal of produced fluids in connection with oil and gas
exploration and production used as part of the filtering and/or settling process
upstream of a National Pollutant Discharge Elimination System (NPDES)
discharge point;

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-21

Table C-7. Summary of Regulations for E&P Wastes in Wyoming
Topic Area Summary
Definitions (cont.)
(C) Pits constructed in association with heater treaters or other dehydration
equipment used in production, such as free water knockouts, or first, second and third
stage separators;
(D) Pits constructed for blowdown or gas flaring purposes. (iv) Pits constructed for the
storage and treatment of heavy sludges, oils, or basic sediment and water (BS&W) in
connection with production operations;
(v) Temporary pits constructed during well workovers, including spent acid and frac fluid
pits;
(vi) Permanent or temporary emergency use pits;
(vii) Miscellaneous pits associated with oil and gas production not listed above.
Waste Unit Location
Requirements
Wyoming residential setback requirements for wells and production facilities address
occupied structures (residential, school, business, and hospital use). Pits are prohibited
“in drainages, or in the floodplain of a flowing or intermittent stream, or in an area where
there is standing water during any portion of the year” and unlined pits are prohibited in
fill material. Critical areas for pit placement are also defined and include criteria for
distances to water supplies and wetlands, residences and other structures, groundwater
depth, total dissolved solids content and soil type. While pits are not prohibited in critical
areas, they may require additional protection. In addition, the Wyoming Environmental
Quality Act restricts any commercial oil field waste disposal facility from being
constructed or operated within one mile of any occupied dwelling or any public or private
school, without approval.
Endangered species are not specifically addressed in the regulations; however the
regulations do indicate the Commission shall adopt policies and practices that may be
required in compliance with the Greater Sage-Grouse Core Protection Area.
Tank Requirements
Rules include general performance requirements of tanks (“maintain tanks in a work-like
manner which will preclude seepage from their confines and provide for all applicable
safety measures”). The use of crude oil tanks without tops is strictly prohibited. There are
no specific requirements in the oil and gas regulations for berm and containment
materials for tanks, or for protective netting and tank monitoring. However, “If an SPCC
Plan is applicable, any oil spilled within the SPCC containment berms at a tank battery
shall be promptly removed and any containment devices installed to contain drips and
spills during hose hookup shall be emptied and/or cleaned as necessary to prevent access
by wildlife, domestic animals, or migratory birds.” A permit is not required for tank bottom
removal, but disposal of produced water, tank bottoms and other miscellaneous solid
waste should be in a manner which is in compliance with the Commission’s rules or other
state, federal, or local regulations. Modular large volume tanks are not specifically
addressed in the regulations.
Pit Construction and
Operation Requirements
WOGCC rules cover construction and operation of various pit types, including reserve
pits, produced water pits, skim pits, emergency pits, temporary pits and miscellaneous
pits. Emergency pits are defined as temporary pits. Pits in critical areas with groundwater
less than 20 feet are prohibited, and unlined pits shall not be constructed in fill. Reserve
pits cannot be used as production pits; hazardous waste pits are prohibited.

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Appendix C: State Programs C-22

Table C-7. Summary of Regulations for E&P Wastes in Wyoming
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Liners are required for pits constructed in fill or those retaining oil base drilling muds,
high density brines, and/or completion or treating fluids, or if the produced water has a
total dissolved solids concentration greater than 10,000 mg/L. Details for liners and slopes
(3:1) are provided, while general guidelines are included for freeboard (Liquids must be
kept at a level that takes into account extreme precipitation events and prevents
overtopping and unpermitted discharges.) Specifications for other elements of pit
construction and operation including run-on/run-off controls and berm construction are
not included in these rules. Fencing is required for all pits and netting is necessary when
timely removal of fluid is not possible. Signage is required for each pit, unless in close
proximity to marked wells.
Discharge permits are required to discharge stormwater that has come in contact with
any overburden, raw material, intermediate products, finished products, byproducts or
waste products located on the site. Storm water discharges associated with small
construction activity require permit authorization as of March 10, 2005.
A groundwater baseline sampling, analysis and monitoring plan for the site (not specific
to pits) is required as part of the application to drill or deepen a well. “Monitoring systems
may be required for pits constructed in sensitive areas [as specified in the permit]. Such
pits must be operated in a manner that avoids damage to liner integrity. Periodic
inspections, weekly at a minimum, of pits must be made by the Owner or Operator and
documentation of such inspections may be required to be submitted to the Supervisor
at his request… The Supervisor is also authorized to require the testing necessary for the
regulation of oil field pits and wastes.”
Permits for noncommercial centralized pits may be more stringent than for individual
pits; they are issued for a five-year term and may be renewed at the discretion of the
Supervisor. Noncommercial fluid recycling pits are not specifically addressed in these
regulations.
Pit Closure Requirements
Pit closure may include evaporation and subsequent burial of solids depending on the
fluids, type of pit and solids content. Burial methods cannot compromise the integrity of
the liner without written approval by the Supervisor. One-time landspreading of reserve
pit fluids on the drilling pad may be approved. Trenching or squeezing of pits is expressly
prohibited. Notice (24 hours) is required prior to pit closure to allow the Commission staff
to witness closure operations. Commercial treatment of pits may be approved.
Pit reclamation should be completed in a timely manner as climatic conditions allow.
Production and reserve pits should be reclaimed after they have dried sufficiently
following removal of any oil, sheens or other hydrocarbons, and no later than one year
after the date of last use, unless a variance is granted. High salt content materials must
be removed prior to pit closure. Inspections may be required (at the Commission’s
option), and sampling is determined by the Supervisor based upon site-specific
conditions. All disturbed areas on state lands will be reseeded. A Sundry Notice shall be
submitted upon completion of pit closure. Pit bonds may be required.
Pits used solely for the retention of water produced in association with the recovery of
coalbed methane gas in the Powder River Basin may be left open with approval.
Spill Notification
Oil and gas rules indicate that uncontained spills or unauthorized releases of produced
fluids, drilling muds, produced water, hydrocarbons, or chemicals which enter, or threaten
to enter, waters of the state must be verbally reported to the Commission no later than
the next business day following discovery of the incident. The Owner or Operator shall
file a written report within 15 working days. Notification for contained spills depends
upon the volume of the spill.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-23

Table C-7. Summary of Regulations for E&P Wastes in Wyoming
Topic Area Summary
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
Regulations for offsite disposal are unclear. Testing of the waste is determined by the
Supervisor based upon site-specific conditions. Regulations do not address drill cuttings
as daily cover in landfill.
Land Application

Beneficial Use
Regulations related to land application and beneficial use are intertwined in the
regulations and may be somewhat confusing. Landfarming and landspreading must be
approved by the Department of Environmental Quality, whereas jurisdiction over
roadspreading or road application is shared by DEQ and the Commission. The
Commission is the agency responsible for permitting road applications of E&P wastes in
drilling fluids, produced water and produced water-contaminated soils, waste crude oil,
sludges, and oil-contaminated soils inside the boundaries of a lease, unit, or
communitized area. Landfarming, landspreading, and roadspreading shall be protective
of human health and the environment and shall be performed in compliance with all
other applicable State and Federal regulations and requirements.” Testing and analysis
are required on permit applications for road application of wastes.
Waste Minimization/
Management
Depending upon location of pit, the Commission may make modifications as necessary
to provide additional protection from site activities, which may include running a closed
drilling system. In areas where groundwater is less than 20 feet below the surface, a closed
system must be utilized for well drilling operations.
“The Commission encourages the recycling of drilling fluids and by administrative action
approves the transfer of drilling fluids intended for recycling. When removed as a product
for use in a drilling operation on another lease, drilling fluid is not classified as a waste. If
federal leases are involved, the Owner or Operator must obtain the approval of the
Bureau of Land Management (BLM). The Supervisor requires the following information
be included on the Form 14B or on a Sundry Notice (Form 4) estimated volume, estimated
date of transfer, mud recap, analyses which include at a minimum, pH, chlorides, and oil
and grease. To protect shallow groundwater, drilling muds with chlorides testing in excess
of 3,000 parts per million or those containing hydrocarbons cannot be used in drilling
operations until after the surface casing has been set.”
Commercial Recycling and
Reclamation Facilities Regulations do not address commercial recycling or reclamation facilities.
NORM and TENORM
The Wyoming Department of Environmental Quality, Solid and Hazardous Waste Division
(SHWD) provides guidelines regarding NORM, which is considered a solid waste, and
states the regulation of NORM is supported by existing statutes and regulations. Solid
waste disposal is allowed up to 50 pCi/g of radium-226 but the volume accepted depends
on the concentration. Up to 20 cubic yards of waste containing NORM between
background (or 8pCi/g) and 30 pCi/g of radium-226 may be disposed in a state-
permitted solid waste disposal facility with approval from the landfill operator, and may
be stored for up to one year without prior written authorization from SHWD. Up to 10
cubic yards with NORM between 30 and 50 pCi/g may be disposed in a state-permitted
solid waste disposal facility with approval from the landfill operator and a minimum 4-
feet of approved cover material. Such waste may be stored for a period not to exceed
180 days without prior written authorization from SHWD. NORM/TENORM wastes
exceeding 50 pCi/g of radium-226 cannot be disposed in conventional solid waste
facilities in Wyoming and must be disposed at facilities outside of Wyoming that accept
such low-level radioactive waste.
Oil and gas regulations do not address NORM/TENORM.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-24

C.8. New Mexico
In 2016, New Mexico accounted for approximately 4.6% of the nation’s oil and gas production
according to the U.S. Energy Information Agency. Oil and gas are produced from both conventional
and unconventional resources, and the state also has coal bed methane production. The New Mexico
Oil Conservation Division (OCD) within the Department of Energy, Minerals and Natural Resources
regulates oil and natural gas production. The Environmental Improvement Board is responsible for the
promulgation of rules and standards in many areas including food protection, air, radiation, waste,
drinking water and others. NORM related to oil and natural gas production is regulated by both the
New Mexico Oil Conservation Division and the Environmental Improvement Board.
OCD has promulgated a set of 15 rules (chapters) which include extensive requirements for waste
management. Title 19, Chapter 15, Part 17 (Pits, Closed-Loop Systems, Below-Grade Tanks and Sumps)
was updated in June 2013. Most sections in Part 2 (General Provisions for Oil and Gas Operations) were
updated in December 2008 but a few were amended several times since then including the latest in
June 2018. The waste management practices (produced water, drilling fluids, liquid wastes, and surface
waste management facilities were updated in 2015 and 2016. Table C-8 provides a summary of the
regulations identified for E&P wastes in New Mexico.
Table C-8. Summary of Regulations for E&P Wastes in New Mexico
Topic Area Summary
Definitions
Approximately 180 definitions are provided in the general provisions for oil and gas
operations (Title 19, Chapter 15, Part 2). Twenty additional definitions are provided in Part
17 (Pits, Closed-Loop Systems, Below-Grade Tanks and Sumps), which include four types
of pits: emergency pit, multi-well fluid management pit, permanent pit and temporary
pit. Additional definitions are included in other sections of the regulations. The definitions
of pits are comprehensive and sometimes include regulations on their use. For example,
the definition of multi-well fluid management pit notes that it can not be used for
disposal of drilling, completion or other waste, and any additional of wells for the pit use
must go to a hearing.
Waste Unit Location
Requirements
Detailed siting requirements are provided for temporary pits (containing low chloride
fluids or not low chloride fluids), permanent pit or multi-well fluid management pits,
material excavated during pit construction and below-grade tanks. For example, setbacks
for various pits range from 300 to 1,000 feet from residential buildings and 100 to 500
feet from a wetland. Minimum depth to groundwater ranges from 25 to 50 feet below
the bottom of the pit/tank depending on the type. Emergency pits are exempt from such
location restrictions. Siting requirements are comprehensive and include criteria such as
streams, playas, sinkholes, unstable areas, municipal boundaries (not allowed within
municipal boundaries), wells, wetlands, mines, and floodplains. Endangered species are
not specifically addressed in the siting and location requirements.

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Appendix C: State Programs C-25

Table C-8. Summary of Regulations for E&P Wastes in New Mexico
Topic Area Summary
Tank Requirements
Tank requirements for below-grade tanks are included in the pit requirements and be
“constructed of materials resistant to the below-grade tank’s particular contents and
resistant to damage from sunlight.” Above ground open-top tanks require screen, nets
or be otherwise rendered non-hazardous to wildlife, including migratory birds. Where
netting or screening is not feasible, the operator shall on a monthly basis inspect for, and
within 30 days of discovery, report discovery of dead migratory birds or other wildlife to
the appropriate wildlife agency and to the appropriate division district office in order to
facilitate assessment and implementation of measures to prevent incidents from
reoccurring. Berms (fire walls) are not required unless tanks are within the city limit or
1000 feet from a residence.
Oil and gas regulations include limited requirements for construction or operation of
above ground tanks, but the Petroleum Storage Tank division regulates crude oil tanks
and has extensive regulations for construction and operation.
Modular large volume tanks, tank monitoring and tank bottom removal are not
specifically addressed in the oil and gas regulations.
Pit Construction and
Operation Requirements
Extensive construction and operation requirements are provided for temporary pits,
permanent pits and multi-well pits. Permits are required for such pits, and unlined pits
are prohibited. The application requirements for pit permits differs for each type of pit
and require information on the design, operating, maintenance and closure. Permanent
pit design must be signed by a registered engineer.
Liner requirements vary by pit type and range from single geomembrane liner
(temporary) to primary and secondary liners with a leak detection system (permanent and
multi-well). Additional construction details including pit slope, liner installation and
performance criteria are provided in the regulations. Signs, fencing and netting are
required. A separate pit sign is only required if the pit is not associated with a well site
where a sign is already posted. OCD must be given the opportunity to inspect the pit
prior to liner installation.
Minimum depth to groundwater ranges from 25 to 50 feet depending on pit type. A
freeboard of 3 feet is required for permanent pits, and the volume of a temporary pit can
not exceed 10-acre feet including freeboard. Specifications for berms, ditches and other
diversions are not provided but should be constructed to prevent run-on of surface water.
The pit application package requires a hydrologic analysis of the proposed pit location
and detailed design and operation information.
An approved discharge plan is required for some discharges, and a permit is required for
the discharge of hydrostatic test water. Groundwater monitoring of the pit or well site is
not required but inspections are mandated and operators must inspect pits on daily or
weekly basis, depending on pit use, as specified in the regulations.
Noncommercial fluid recycling pits are specifically addressed in the regulations and have
an extensive set of design requirements and operational requirements. No permit is
required for recycling facilities if the water is used for drilling, completion, producing,
secondary recovery, pressure maintenance or plugging of wells. Evaporation, storage,
treatment and skimmer ponds are addressed in a separate set of regulations and include
detailed technical requirements for design and operation.

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Appendix C: State Programs C-26

Table C-8. Summary of Regulations for E&P Wastes in New Mexico
Topic Area Summary
Pit Closure Requirements
Pit closure requirements are well defined in the OCD regulations. A closure plan
describing the closure method and procedures is required for all pit types as part of the
pit permit application process. Requirements for pit closure are provided based on the
final disposal location of the waste (off-site disposal or buried in place). Liquids removal
is required prior to pit closure, and solids removal is necessary for off-site disposal. Burial
in place is allowed but testing of waste and oils is required. Waste stabilization and a
covering by a liner may be required. A closure schedule and sampling requirements
(number of samples, analytes and methods) are included in the regulations. Financial
security is required for the general well permit, not pits specifically.
Inspections of pit closure are not required, but the OCD must be notified prior to pit
closure.
Spill Notification

Release notification is discussed “To require persons who operate or control the release
or the location of the release to report the unauthorized release of oil, gases, produced
water, condensate or oil field waste including regulated NORM, or other oil field related
chemicals, contaminants or mixtures of those chemicals or contaminants that occur
during drilling, producing, storing, disposing, injecting, transporting, servicing or
processing and to establish reporting procedures.”
Notification for a major release includes immediate verbal notification (within 24 hours)
and follow-up written notification within 15 days; minor release requires only written
notification (within 15 days). A major release includes (1) an unauthorized release of a
volume, excluding gases, in excess of 25 barrels; (2) an unauthorized release of a volume
that: (a) results in a fire; (b) will reach a watercourse; (c) may with reasonable probability
endanger public health; or (d) results in substantial damage to property or the
environment; (3) an unauthorized release of gases in excess of 500 MCF; or (4) a release
of a volume that may with reasonable probability be detrimental to water or exceed the
standards in Subsections A and B or C of 19.15.30.9 NMAC.
Minor release means an unauthorized release of a volume, greater than five barrels but
not more than 25 barrels; or greater than 50 MCF but less than 500 MCF of gases.
Corrective Action
Corrective action is specified as “The responsible person shall complete division-
approved corrective action for releases that endanger public health or the environment.
The responsible person shall address releases in accordance with a remediation plan
submitted to and approved by the division or with an abatement plan submitted in
accordance with 19.15.30 NMAC.”
Title 19, Chapter 15, Part 30 (Remediation) has the following objective: “To abate pollution
of subsurface water so that ground water of the state that has a background
concentration of 10,000 mg/l or less TDS is either remediated or protected for use as
domestic, industrial and agricultural water supply, and to remediate or protect those
segments of surface waters that are gaining because of subsurface-water inflow for uses
designated in the water quality standards for interstate and intrastate surface waters in
New Mexico, 20.6.4 NMAC; and abate surface-water pollution so that surface waters of
the state are remediated or protected for designated or attainable uses as defined in the
water quality standards for interstate and intrastate surface waters in New Mexico, 20.6.4
NMAC.”

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Appendix C: State Programs C-27

Table C-8. Summary of Regulations for E&P Wastes in New Mexico
Topic Area Summary
Off-site Landfills
Disposal of E&P waste is allowed at commercial and non-commercial (operator owned)
solid waste facilities as specified in the regulations. Regulations contain an extensive set
of requirements for construction, operation, closure and post closure of surface waste
management facilities (centralized facilities, landfills, small landfarms, large landfarms,
evaporation ponds, treatment ponds and skimmer ponds. Signs are required for all
subsurface facilities (landfills and landfarms) and permits are required for all facilities
except small landfarms (less than 2 acres and 2000 cubic yards of waste). Testing is
required prior to disposal. In addition, produced water may be processed at “recycling
facilities such as skimmer and evaporate ponds. Permitted solid waste facilities require
financial security.
Solid waste guidance allow use of treated petroleum contaminated waste as an
alternative daily cover if it meets soil quality criteria for the facility.
Land Application

E&P waste consisting of soil and drill cuttings predominately contaminated by petroleum
hydrocarbons may be landfarmed. Specifications and conditions for landfarming are
included in the regulations (for example, the waste must be sufficiently free of liquid
content to pass the paint filter test and background testing is required prior to land
application). A land farm permit is required for large landfarms and Form C-137 is
required for small landfarm.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling and recycling of produced water are considered best management
practices but are not required.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are addressed in these
regulations, including monitoring/testing during operation and financial security/closure.
An offsite reclamation manifest is not required.
NORM and TENORM
NORM is defined in the environmental regulations and also addressed in a separate
section of the oil and gas regulations. Under the oil and gas regulations, NORM with less
than 30 pCi/g Ra 226 or 150 pCi/g of any other radionuclide is exempt from disposal
regulation. Disposal limitations and conditions are based on the general permit
conditions provided in the regulations, and may be allowed at commercial or centralized
surface waste management facilities, plugged and abandoned wells and injection wells.
Regulations specifically allow NORM to be disposed at or near the surface at the site of
generation. An action plan/management plan is required, and testing is required prior to
disposal.
Storage requirements for regulated NORM are provided in the regulations.

C.9. Louisiana
In 2016, Louisiana accounted for approximately 4.4% of the nation’s oil and gas production, according
to the U.S. Energy Information Agency. Louisiana has long history of producing oil and gas from
conventional reservoirs but has recently increased unconventional production from the Haynesville
and Tuscaloosa Marine Shale. Less than 10% of Louisiana’s oil and gas production is from offshore,
state-controlled lands. The Department of Natural Resources has three offices that oversee oil and gas
resources in Louisiana: The Office of Conservation, the Office of Mineral Resources and the Office of
Coastal Management. The Geological Oil and Gas Division within the Office of Conservation regulates

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-28

oil and gas production activities. The Louisiana Department of Environmental Quality, Office of
Environmental Compliance, Division of Emergency and Radiological Services regulates NORM in the
state.
Oil and gas regulations included in Title 43 Natural Resources, Part XIX Office of Conservation are
current as of March 2017, but the regains did not specify when the sections were last updated. NORM
regulations contained in Title 33 Environmental Quality, Part XV Radiation Protection are dated
October 2014. A new rule regarding hydraulic fracturing in the Haynesville Shale became effective in
2011.. Table C-9 provides a summary of the regulations identified for E&P wastes in Louisiana.
Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Definitions
Approximately 50 definitions are provided for the storage, treatment and disposal of E&P
waste in the Definitions section of Chapters 3 (on-site) and 5 (off-site) of Title 43.
In Chapter 3 (on-site), a pit is defined as “for purposes of this Chapter, a natural
topographic depression or man-made excavation used to hold produced water or other
exploration and production waste, hydrocarbon storage brine, or mining water. The term
does not include lined sumps less than 660 gallons or containment dikes, ring levees or
firewalls constructed around oil and gas facilities.” A slightly different version is presented
in Chapter 5 (off-site) where a pit is defined as “an earthen surface impoundment
constructed to retain E&P Waste, often referred to as a pond or lagoon. The term does
not include lined sumps less than 660 gallons.”
Production Pits are defined as either earthen or lined storage pits for collecting E&P
Waste sediment periodically cleaned from tanks and other producing facilities, for storage
of produced water or other exploration and production wastes produced from the
operation of oil and gas facilities, or used in conjunction with hydrocarbon storage and
solution mining operations, and include the following types:
1. Burn Pits―earthen pits intended for use as a place to temporarily store and
periodically burn exploration and production waste (excluding produced water)
collected from tanks and facilities.
2. Compressor Station Pits―lined or earthen pits intended for temporary storage or
disposal of fresh water condensed from natural gas at a gas pipeline drip or gas
compressor station.
3. Natural Gas Processing Plant Pits―lined or earthen pits used for the storage of
process waters or stormwater runoff. No produced water may be stored in a natural
gas processing plant pit.
4. Produced Water Pits―lined or earthen pit used for storing produced water and other
exploration and production wastes, hydrocarbon storage brine, or mining water.
5. Washout Pits―lined earthen pits used to collect wash water generated by the
cleaning of vacuum truck tanks and other vessels and equipment only used to
transport exploration and production waste. Any materials other than E&P Waste are
prohibited from being placed in such pits.
6. Well Test Pits―small earthen pits intended for use to periodically test or clean up a
well.
7. Emergency Pits―lined or earthen pits used to periodically collect produced water
and other E&P Waste fluids only during emergency incidents, rupture or failure of
other facilities.

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Appendix C: State Programs C-29

Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Definitions (Cont.)
8. Onshore Terminal Pits―lined or earthen pits located in the coastal area used for
storing produced water at terminals that receive crude oil and entrained water by
pipeline from offshore oil and gas production facilities.
9. Salt Dome Cavern Pits―lined or earthen pits located in the coastal area associated
with the storage of petroleum products and petroleum in salt dome caverns.
Reserve pits are also defined as “temporary earthen pits used to store only those materials
used or generated in drilling and workover operations.”
Waste Unit Location
Requirements
Production pits, may not be constructed in certain flood hazard boundary areas unless
such pits have levees which have been built at least 1 foot above the 100-year flood level
and able to withstand the predicted velocity of the 100-year flood. Location, construction
and use of such pits is discouraged. These levee height requirements do not apply to
production pits less than 10’x10’x4’ deep, contain only brine and produce less than or
equal to one barrel of saltwater per day.
On-site burn pits and well test pits shall not be located less than 100 feet from a well
location, tank battery, separator, heater-treater, or any and all other equipment that may
present a fire hazard. Unlined pits and burial cells shall not be deeper than five feet above
the high seasonal water table. Contamination of a groundwater aquifer or a USDW with
E&P waste is strictly prohibited. In addition, the injection of E&P Waste into a
groundwater aquifer or a USDW is strictly prohibited.
Commercial solid waste facilities and transfer stations may not be within 1/4 mile of a
public water supply well or within 1,000 feet of a private water supply well for facilities
permitted after January 1, 2002. Commercial facilities and transfer stations may not be
located in any area: where such area, or any portion thereof, has been designated as
wetlands by the U.S. Corps of Engineers during, or prior to, initial facility application
review, unless the applicable wetland and DNR Coastal Management Division coastal use
permits are obtained. Specifications for flood areas discussed above also apply to these
facilities.
Commercial facilities and transfer stations may not be within 500 feet of a residential,
commercial, or public building, church, school or hospital. Additional setbacks are
necessary when the perimeter of Type A land treatment units are within the restricted
residential area for storage tank sludges and gas [plant wastes waste types 6 and 12
(depending on concentration of total benzene). [Type A Facility―a commercial E&P
Waste disposal facility within the state that utilizes technologies appropriate for the
receipt, storage, treatment, or disposal of E&P Waste solids and fluids (liquids) for a fee
or other consideration. Type B Facility―a commercial E&P Waste disposal facility within
the state that utilizes underground injection technology for the receipt, storage,
treatment, and disposal of only saltwater or other E&P Waste fluids (liquids) for a fee or
other consideration.] Transfer stations are exempt from the location requirement of 500
feet from a commercial building.
Location restrictions for land treatment units are discussed in that section below.
Endangered species are not specifically addressed in the oil and gas regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-30

Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Tank Requirements
Commercial facilities and transfer stations shall be operated in compliance with, but not
limited to, the following:
1. The area within the confines of tank retaining walls (levees) shall be kept free of
debris, trash, and accumulations of oil or other materials which may constitute a fire
hazard. Portable gasoline powered engines and pumps must be supervised at all
times of operation and stored at least 50' from tank battery firewalls when not in
use. Vent lines must be installed on all E&P Waste storage tanks and must extend
outside of tank battery firewalls.
2. The area within the confines of tank retaining walls (levees) must be kept free of
accumulations of E&P waste fluids and water. Such fluids shall be properly disposed
of by injection into a Class II well or discharged in accordance with the conditions
of a discharge permit granted by the appropriate state agency.
3. Tank retaining walls shall be kept free of debris, trash, or overgrowth which would
constitute a fire hazard or hamper or prevent adequate inspection.
4. Tank retaining walls (levees) must be constructed of soils which are placed and
compacted in such a manner as to produce a barrier to horizontal movement of
fluids. The levees must be properly tied into the barrier along the bottom and sides
of the levees. All levees must be provided with a means to prevent erosion and other
degradation.
“Each permanent oil tank or battery of tanks that are located within the corporate limits
of any city, town or village, or where such tanks are closer than 500 feet to any highway
or inhabited dwelling or closer than 1000 feet to any school or church, or where such
tanks are so located as to be deemed a hazard by the Commissioner of Conservation,
must be surrounded by a dike (or firewall) or retaining wall of at least the capacity of such
tank or battery of tanks, with the exception of such areas where such dikes (or firewalls)
or retaining walls would be impossible such as in water areas. At the discretion of the
Commissioner of Conservation, firewalls of 100% capacity can be required where other
conditions or circumstances warrant their construction.
1. In water, swamp or marsh areas, where the building of firewalls is impossible or
impracticable, in the future, permanent tanks shall be placed on an impervious
platform surrounded by a metal gutter to catch all the oil and other wastes which
may cause either a fire-hazard or pollution. A sump shall be provided to catch the
run-off from the gutters; however, if the operator or company has devised a plan
which serves the same purpose, the District Manager may after being presented
with the plan, waive the above requirements.
2. Tanks not falling in the above categories (Paragraphs 1 and 2) must be surrounded
by a retaining wall, or must be suitably ditched to a collecting sump, each of
sufficient capacity to contain the spillage and prevent pollution of the surrounding
areas.”
Netting, modular large volume tanks, monitoring, construction and tank bottom removal
are not specifically addressed in the oil and gas regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-31

Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Pit Construction and
Operation Requirements
The following pit types are defined and separate specifications are provided in the
regulations for Produced Water, Onshore Terminal, and Washout Pits; Reserve Pits; Burn
Pits; Well Test Pits; Emergency Pits; Natural Gas Processing Plant Pits, Compressor Station
Pits, and Salt Dome Cavern Pits.
Permits are required for injection wells, and signage is required for the well site; neither
are required for pits specifically.
Production pits (except as noted below) require a liner with a hydraulic conductivity no
greater than 1 x 10-7 cm/sec for 3 continuous feet of clay, which may include the
following types of liners: natural liner; soil/mixture liner, recompacted clay liner,
manufactured liner or a combination liner. An alternate groundwater aquifer and USDW
protection system may be approved by the Office of Conservation.
Pits constructed with a manufactured liner must have side slopes of 3:1 and the liner at
the top of the pit must be buried in a 1' wide and 1' deep trench. Sufficient excess liner
material shall be placed in the pit to prevent tearing when filled with E&P waste.
Pits that meet the following criteria are not required to have a liner: production pits
located within an 'A' zone (FEMA - One-percent-annual-chance flood event) that are less
than or equal to 10' x 10' x 4' deep; contain only produced brine; and is utilized for gas
wells producing less than 25 mcf per day and less than or equal to one barrel of saltwater
per day (bswpd).
Burn pits, compressor station pits, natural gas processing plant pits, well test pits, salt
dome cavern pits are exempt from the liner requirements above. Produced water pits,
washout pits and onshore terminal pits located in the coastal area shall comply with the
above requirements, unless such pit is subject to an approved Louisiana Water Discharge
Permit System permit.
For Emergency Pits, groundwater aquifer and USDW protection shall be evaluated on a
case-by-case basis. Operators who intend to utilize existing or new emergency pits
without liners must demonstrate by written application to the Office of Conservation that
groundwater aquifer and USDW contamination will not occur; otherwise, emergency pits
shall be lined. Applications to demonstrate unlined pits will not contaminate groundwater
aquifers and USDW's shall at a minimum address the following: Emergency Incident Rate,
soil properties, Groundwater Aquifer Evaluation, and Produced Water Composition (total
dissolved solids and oil and grease).
All emergency pits required to be lined must conform to hydraulic conductivity
requirements (1 x 10-7 cm/sec for 3 continuous feet of clay). No produced water or any
other E&P Waste shall be intentionally placed in any emergency pit not meeting the
hydraulic conductivity requirements, except in the case of an emergency incident. In
emergency situations, notice must be given to the Office of Conservation within 24 hours
after discovery of the incident. Produced water and any other E&P Waste must be
removed from the pit within seven days following termination of the emergency situation.
Levees or walls are necessary to protect pits from surface water flow and serve as
secondary containment. Specific requirements for levees are only provided for flood areas
(levees must be constructed at least 1 foot above the 100-year flood elevation) and
coastal areas (levees must have an elevation of at least 2 feet above mean high tide). A
freeboard of 2 feet is required from the top of the pit/levee.
Unlined pits shall not be within 5 feet of the seasonal high groundwater table. Minimum
depth to groundwater is not specified for other pit types.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-32

Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Upon a determination by the operator or the Office of Conservation that any pit subject
to this rule is likely to contaminate a groundwater aquifer or a USDW, the Office of
Conservation shall require the timely submission of a plan for the prevention of such
contamination. Such plan may include using an under-built drainage and collection
system, monitoring wells, and/or other means that the Office of Conservation may
approve to prevent or detect contamination. Any required monitor wells shall be
registered with the appropriate state agency. When required, monitoring shall be
conducted on a quarterly schedule. A written report summarizing the results of such
monitoring shall be submitted to the Office of Conservation within 30 days of the end of
each quarter.
Except for reserve pits, operators must notify the Office of Conservation of the intent to
construct new pits at least 10 days prior to start of construction. Notification shall contain
all information requested in §305.D or §303.K.4 as appropriate. The Office of Conservation
may inspect any proposed pit site prior to or during construction; however, initial use of
the completed pit need not be deferred if no inspection is made.
A waste management and operations plan (WMOP) is required for commercial facilities
and transfer stations and should include "a plan for routine inspection and maintenance
of monitoring equipment (e.g., gauges, monitor wells, etc.) to ensure and demonstrate
compliance with permit and regulatory requirements."
Reserve pits are defined as "temporary earthen pits used to store only those materials
used or generated in drilling and workover operations." Emergency pits are also
discussed, which are only to be used during emergencies.
Leak detection monitoring, noncommercial fluid recycling pits and centralized pits are
not specifically addressed in the regulations.
Discharges into man-made or natural drainage or directly into state waters will be allowed
only after the necessary discharge permit has been obtained from the appropriate state
and/or federal agencies and in accordance with the conditions of such permit. A Louisiana
Water Discharge Permit System (LWDPS) permit may be required.
Pit Closure Requirements
A variety of pit closure techniques are allowed: onsite land treatment, burial, solidification,
onsite land development, or other techniques approved by the Office of Conservation.
Otherwise, all E&P waste must be manifested and transported offsite to a permitted
commercial facility unless temporarily used in hydraulic fracture stimulation operations
conducted on the Haynesville Shale Zone. Details are provided for each process but
specifications about liquids and solids removal is not included specifically.
A pit being closed by passive closure (not defined in the regulations) does require
inspection by a conservation enforcement officer. Inspections do not appear to be
necessary for other pit closure activities. However, documentation of testing and closure
activities, including onsite disposal of E&P waste, shall be maintained in operator's files
for at least three years after completion of closure activities. Upon notification, the Office
of Conservation may require the operator to furnish these data for verification of proper
closure of any pit. If proper onsite closure has not been accomplished, the operator will
be required to bring the site into compliance with applicable requirements.
Sampling is required prior to closure of any pit and for all closure and onsite and offsite
disposal techniques excluding subsurface injection of reserve pit fluids. O&G waste must
be analyzed for the following: pH, total metals (arsenic, barium, cadmium, chromium,
lead, mercury, selenium, silver, zinc), oil and grease, soluble salts and cationic
distributions, and radioisotopes (for pits located in the coastal area closed after October
20, 1990).

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Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Pit Closure Requirements
(Cont.)
Financial security is required for the well site and associated activities. Financial security
shall remain in effect until release thereof is granted by the commissioner pursuant to
written request by the operator. Such release shall only be granted after plugging and
abandonment and associated site restoration is completed and inspection thereof
indicates compliance with applicable regulations or upon transfer of such well to an
exempt operator. Plugging and abandonment of a well, associated site restoration, and
release of financial security constitutes a rebuttable presumption of proper closure but
does not relieve the operator from further claim by the commissioner should it be
determined that further remedial action is required.
Commercial facilities and transfer stations shall maintain a bond or irrevocable letter of
credit on file with the Office of Conservation to provide for adequate closure of the facility.
A closure schedule was not provided in the regulations.
Spill Notification
A waste management and operations plan (WMOP) is required for commercial facilities
and transfer stations and should include "a contingency plan for reporting, responding
to and cleaning up spills, leaks, and releases of E&P Wastes or treatment byproducts,
including provisions for notifying applicable local, state and federal emergency response
authorities and for taking operator-initiated emergency response actions."
Any spills that occur during the offsite transportation of E&P waste shall be reported by
phone to the Office of Conservation, within 24 hours of the spill and the appropriate state
and federal agencies. Information regarding spills at the well site are not provided in these
regulations.
Corrective Action
Corrective actions resulting from spills are not specifically addressed in the regulations.
If monitoring of a groundwater aquifer or USDW indicates contamination due to a
discharge from a pit, the owner or operator shall immediately notify the Office of
Conservation. Within 30 days, the operator shall empty the pit of all E&P Waste and
submit a remedial plan for prevention of further contamination of any groundwater
aquifer or any USDW. Upon approval, the remedial plan shall be implemented by the
operator and monthly progress reports, reviewing actions taken under the plan and their
results, will be filed with the Office of Conservation until all actions called for in the plan
have been satisfactorily completed.
Off-site Landfills
Regulations state “At the option of the generator, E&P waste may be treated and/or
disposed at Department of Natural Resources (DNR) permitted commercial facilities and
transfer stations under the provisions of this Chapter or Department of Environmental
Quality (DEQ) permitted facilities as defined by LAC 33:V and VII which are permitted to
receive E&P Waste which are subject to relevant DEQ regulations. If received, stored,
treated and/or disposed at a DEQ regulated facility, E&P waste would become the sole
regulatory responsibility of DEQ upon receipt.” It is unclear which type of DEQ regulated
facility accepts E&P waste.
Waste characterization is required prior to offsite storage, treatment or disposal. At a
minimum, E&P Waste should be tested for the following constituents: pH, TPH, EC, TCLP
benzene, SAR, ESP and the following metals: As, Ba, Cd, Cr, Cu, Pb, Hg, Mo, Ni, Se, Ag and
Zn.
E&P waste may be re-used as daily cover at a sanitary landfill if compliance with testing
criteria is achieved for moisture content, pH, EC, SAR, ESP, total barium, leachate testing
for TPH and chlorides, benzene, metals and NORM. The use of reusable material in a
sanitary landfill will require written approval of the Department of Environmental Quality.

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Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Land Application
Land application of E&P waste is permitted both on-site and at off-site commercial
facilities. Onsite land treatment allows for pits to be closed by mixing waste with soil from
pit levees or wall and adjacent areas, as long as the waste/soil mixture does not exceed a
pH of 6-9 and specified criteria for metals.
Land treatment in submerged wetland, elevated wetland, and upland areas is permitted
if the oil and grease content of the waste/soil mixture after closure is < 1% (dry weight).
Additional parameters (EC, SAR and ESP) are provided for elevated freshwater wetland
areas where the disposal site is not normally inundated and upland areas.
Land treatment at off-site facilities have additional requirements: they shall be isolated
from contact with public, private or livestock water supplies, both surface and
underground; soil shall contain a slowly permeable horizon at least 12 inches thick
containing enough fine grained material within 3 feet of the surface to classify it as fine
grained material (CL, OL, MH, CH, or OH under the Unified Soil Classification System) and
the seasonal high water table shall remain at least 36 inches below the soil surface. Land
treatment cells and associated surface drainage system surfaces shall at no time have an
accumulation of oil of more than 1 inch at any surface location, and land treatment cell
levels shall be maintained with at least 2 feet of freeboard at all times.C4
The location restriction for land treatment of E&P wastes is typically 1,000 feet from a
residential/public building, church, school or hospital. However, waste types 06 (storage
tank sludges) and 12 (gas plant waste solids) have additional limitations depending on
their benzene concentrations. For example, waste type 06 with a total benzene
concentration greater than 113 mg/kg and waste type 12 less than 3,198 mg/kg total
benzene may not be within 2000 feet of such buildings, while waste type 12 with total
benzene concentrations greater than 3,198 mg/kg is banned from land treatment.
Beneficial Use
Roadspreading may be conducted using stabilized E&P waste. Reserve pits may be closed
by processing the waste material with Department of Environmental Quality approved
stabilizing additives and using the mixture onsite to develop lease roads, drilling and
production locations, etc. The following conditions must be met for use of waste from
reserve pits: pH range of the mixture: 6-12; electrical conductivity (EC) < 8 mmhos/cm; oil
and grease content < 1% by weight; total metals content meeting the criteria (see
§313.C.2 for limitations), leachate testing for chloride concentration < 500 mg/L; and
NORM concentrations do not exceed applicable DEQ criteria or limits.
Beneficial use of brine is not specifically mentioned in the regulations. Subsurface disposal
of salt water is required and regulated by LAC 43:XIX.401 et seq.
Waste Minimization/
Management
Closed waste storage systems are encouraged but not required. Produced water is not
required to be recycled but may be re-used in hydraulic fracturing stimulation activities
in the Haynesville Shale.
“In order to encourage the conservation and recovery of resources in the oilfield industry,
the processing of E&P Waste into reusable materials, in addition to or beyond extraction
and separation methods which reclaim raw materials such as crude oil, diesel oil, etc., is
recognized as a viable alternative to other methods of disposal.”

C4) Freeboard is most commonly applied to liquid controls, but it also can apply to solid wastes. In this case the waste in the land
treatment cell must not come within two feet of the top of the berm.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-35

Table C-9. Summary of Regulations for E&P Wastes in Louisiana
Topic Area Summary
Commercial Recycling and
Reclamation Facilities
Off-site treatment, storage and disposal of E&P wastes at commercial facilities and
transfer stations is addressed in the regulations. Such activities require approval from the
Commissioner and evidence of financial responsibility. A manifest must accompany each
shipment, and each load of waste must be sampled (pH, electrical conductivity, chloride
(Cl) content and NORM, as required by applicable DEQ regulations and requirements)
and results reported on the manifest. An 8-ounce sample (minimum) of each load must
be collected and labeled with the date, operator and manifest number, and each sample
shall be retained for a period of 30 days.
NORM and TENORM
Louisiana Department of Environmental Quality regulations address NORM waste; oil and
gas regulations in the state do not. Definitions in Chapter 14 (Regulation and Licensing
of NORM) of Title 33 Environmental Quality, Part XV Radiation Protection, include NORM
and TERN (technologically enhanced natural radioactive material). NORM is discussed
with regards to E&P waste, while TERN is not mentioned again in the regulations.
“A general license is hereby issued to mine, extract, receive, possess, own, use, store, and
transfer NORM not exempt in LAC 33:XV.1404 without regard to quantity.” Produced
waters from crude oil and natural gas production are considered exempt.
NORM waste management plan is required to store NORM waste for up to 365 days and
should be submitted to the Office of Environmental Compliance for authorization.
Storage requirements indicate containers (1) shall be compatible with the NORM waste
being stored, (2) shall always be closed and sealed during storage (except when necessary
to add or remove waste), and (3) shall not be opened, handled or stored in a matter that
may cause them to rupture or leak. Storage of NORM in tanks is allowed but waste piles
are prohibited. Inspections of storage areas shall be conducted at least quarterly.
Treatment or disposal of NORM waste shall be in accordance with one of the following:
1. by transfer of the wastes to a land disposal facility licensed by the department, the
U.S. Nuclear Regulatory Commission, an agreement state, or a licensing state;
2. by alternate methods authorized by the department in writing upon application or
upon the department’s initiative. The application for alternative methods of disposal
shall be submitted to the department for approval;
3. for nonhazardous oilfield waste containing NORM at concentrations not exceeding
30 picocuries per gram of radium-226 or radium-228 by transfer to a nonhazardous
oilfield waste commercial facility regulated by the Department of Natural Resources
for treatment if the following are met:
a. dilution in the end product after treatment does not exceed 5 picocuries per gram
above background of radium-226 or radium-228;
b. the nonhazardous oilfield waste commercial facility has a program for screening
incoming shipments to ensure that the 30 picocuries per gram limit of radium-226
or radium-228 is not exceeded; and
c. the Department of Natural Resources (DNR) approves; or
4. for nonhazardous oilfield waste containing concentrations of NORM in excess of the
limits in LAC 33:XV.1404.A.1, but not exceeding 200 picocuries per gram of radium-
226 or radium-228 and daughter products, by treatment at nonhazardous oilfield
waste commercial facilities specifically licensed by the department for such purposes.
Regulation of such sites is set forth in a memorandum of understanding between the
department and DNR and contained in LAC 33XV.1499 .Appendix C.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-36

C.10. Ohio
According to U.S. Energy Information Agency, in 2016 Ohio accounted for approximately 3.4% of the
nation’s oil and gas production and includes both conventional and unconventional resources. E&P
wastes generated in Ohio are regulated by the Ohio Department of Natural Resources (ODNR),
Division of Oil and Gas Resources Management (DOGRM). Wastes disposed offsite fall under the
jurisdiction of Ohio Environmental Protection Agency (Ohio EPA) and NORM (cuttings and brine)
and TENORM are regulated under both radiation protection and the oil and gas rules. Ohio updated
its oil and gas regulations in 2005 to address urban drilling, and again in 2013 for horizontal wells and
related waste management issues. Table C-10 provides a summary of the regulations identified for E&P
wastes in Ohio.
Table C-10. Summary of Regulations for E&P Wastes in Ohio
Topic Area Summary
Definitions
Definitions in the oil and gas regulations cover relatively broad areas (i.e. production
operation includes all activities from pad construction to plugging) and do not include
definitions for different types of pits. “Urbanized areas” and “horizontal wells” have
recently been added to the definitions.
Waste Unit Location
Requirements
Ohio setback requirements for wells and tank batteries address inhabited structures
(residential business and other uses), various water resources, and streets. The regulations
do not address setbacks related to endangered species or wildlife. Pits are not specifically
identified in setback requirements however because they are part of the well pad they
are covered by well setback rules.
Tank Requirements
Tanks can be used to hold any waste or produced materials. Rules include general
performance requirements (“must be constructed and maintained to prevent the escape
of waste”) but cannot be buried without approval. If approved, buried steel tanks must
be steel and catholically protected. There are no specific requirements in the oil and gas
regulations for berm and containment materials for tanks, or for protective netting and
tank monitoring. Modular large volume tanks are not specifically addressed in the
regulations.
Pit Construction and
Operation Requirements
DOGRM rules require a waste management plan as part of the well permit application
including a description of the pit construction and use. Thus, the rules tend to be general
and details are left to the well-specific permits and waste management plans approved
by the agency. Rules cover construction and operation of temporary pits (including
drilling, completion and production uses) and appear to allow the director discretion in
approving and requiring site specific conditions. As of January 2014, pit permits are
required. A general requirement for proper construction and safe operation addresses pit
management (pits of sufficient size and shape must be constructed adjacent to each
drilling well to contain all the drilling muds, cuttings, salt water and oil; no fluid is allowed
to overflow). Pits are not allowed as permanent disposal locations for brine or materials
coming in contact with refined oil-based substances or other sources of contaminants.
Synthetic pit liners are required, but the operator may request a variance. Fencing
(urbanized areas and near inhabited structures only) and signage (for the well, not
specifically for the pit) are required but specifications for other elements of pit
construction and operation including leak detection/monitoring, netting, inspection,
freeboard, run-on/run-off controls and berm construction are not included in the rules.
Centralized pits are not specifically addressed in the regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-37

Table C-10. Summary of Regulations for E&P Wastes in Ohio
Topic Area Summary
Pit Closure Requirements
Closure requirements for pits containing fluids from hydraulic fracturing require removal
of all materials “upon termination of the fracturing process” and drilling pits in urbanized
areas must be closed within thirty days. Inspections and closure sampling are not required
by the regulations. Financial security for pits is not required but is included as a part of
the overall well permit bond.
Spill Notification
New rules require owners and operators to report releases of oil, condensate, brine,
chemical substances and oilfield waste materials that occur above specified thresholds
and outside of appropriate containment into the environment.
Corrective Action Corrective action is not specifically addressed in state regulations.
Off-site Landfills
Drill cuttings that have come into contact with refined oil-based substances or other
sources of contamination must be disposed of at a licensed offsite solid waste landfill
unless otherwise approved by the Division. Cuttings from air or water-based drilling that
have not come into contact with contaminants are not managed as solid waste and may
be buried onsite, if in the approved Waste Management Plan. Oil and gas regulations do
not require testing of the material for offsite disposal, however disposal facility permits
may require testing. Regulations do not address drill cuttings as daily cover in landfill.
Land Application Regulations give flexibility to include land application in the site-specific waste
management plan, but such requests must be approved by the agency.
Beneficial Use
Uncontaminated cuttings may be used offsite for beneficial use but must first obtain
approval from Ohio EPA’s Division of Materials and Waste Management. Ohio allows
county governments to permit the use of brine for road treatment. If the county allows
roadspreading certain requirements must be met regarding the distance from vegetation
and application methods. Brine from horizontal wells, drilling fluids, and flowback are not
allowed to be spread on a road. The brine source must be reported, but fluid testing is
not required under the state regulations.
Waste Minimization/
Management
Best management practice documents for well site construction and pre-drilling water
sampling are noted in the regulations. Ohio does not have a best management practices
manual for E&P waste, however in 2014 ODNR produced a fact sheet summarizing
management practices for cuttings from shale wells. Closed loop drilling is not specifically
addressed in the regulations, but tanks are allowed for containing drilling fluids.
Commercial Recycling and
Reclamation Facilities
Commercial E&P waste recycling or reclamation facilities must have a permit to operate
as of January 2014. A detailed description of the process including estimated waste
volumes is required in the application.
NORM and TENORM
NORM, including brine and uncontaminated cuttings, are not regulated in Ohio. Drilling-
related waste (e.g. tank bottoms, pipe scale, filtrate, recycled cuttings) that is suspected
to be TENORM must be tested for radium-226 and radium-228 before leaving the well
site; TENORM cannot be disposed of at an oil and gas drill site. Solid waste landfills can
only accept TENORM wastes for disposal at concentrations less than 5 pCi/g above
natural background (“natural background” is two picocuries per gram or the actual value
measured at the site).

C.11. West Virginia
In 2016, West Virginia accounted for approximately 3.1% of the nation’s oil and gas production
according to the U.S. Energy Information Agency. Most of West Virginia’s production is from

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-38

unconventional resources in the Marcellus Shale, however there is a small amount of shallow oil
production and coalbed methane production in the state, and deeper intervals have been explored
recently. The Department of Environment Protection regulates oil and natural gas production (Office
of Oil and Gas) and solid waste (Solid Waste Management Section). The West Virginia Department of
Health and Human Resources regulates TENORM related to oil and natural gas production in the state.
West Virginia Code Title 35 contains the oil and gas rules. Series 8 is a new oil and gas rule that became
effective in 2016 for horizontal wells. It is an amendment to the Department of Environmental
Protection, Oil and Gas rules. The new rules require the well application to include a water
management plan describing the disposal procedures for fracturing and stimulation wastewater, and
construction and operation requirements for unconventional wellsite pits and centralized pits. The
section also requires water quality testing of wells and springs within 1,500 feet of the well pad. Title
35 Series 2 (1998) implements the solid waste permit by rule requirements for solid waste facilities at
E&P sites. Table C-11 provides a summary of regulations identified for E&P wastes in West Virginia.
Table C-11. Summary of Regulations for E&P Wastes in West Virginia
Topic Area Summary
Definitions
Approximately 30 definitions are provided in the different parts of oil and gas regulations,
including definitions for pits and impoundments. The definitions do not include many
technical terms. Pits are any man-made excavation or diked area that contains or is
intended to contain an accumulation of process waste fluids, drill cuttings, and/or any
other liquid substance that could impact surface water or groundwater, whereas
impoundments are man-made excavations or diked areas for the retention of fresh water
and into which no wastes of any kind are placed. Definitions do not further divide pit
types.
Technical specifications are provided in many parts of the rules, but some regulations
provide only general requirements or performance-based criteria. For example, tank
construction rules note that tanks for storage of oil or other pollutants must be
compatible with the material stored and the conditions of storage; and, saltwater disposal
facilities should be inspected often.
Waste Unit Location
Requirements
Regulations include general requirements for protection of floodplains, groundwater and
surface water from wells and production facilities. Endangered species are not specifically
addressed in the regulations. Some specifics, however, are provided, such as no oil or gas
well shall be drilled nearer than two hundred feet from an existing water well or dwelling
without first obtaining the written consent of the owner of such water well or dwelling.
Location requirements are also included for centralized pits and impoundments with
capacity of more than 5,000 barrels, which specify a minimum depth to groundwater of
20 inches.
Tank Requirements
General tank requirements indicate that berms should be “…sufficiently impervious to
contain spilled oil…” For drilling, completion, workover and production operations,
secondary containment shall be installed with impermeable basins for tanks used for
stored liquids other than freshwater and shall have a capacity of 110% of the largest tank
within the battery.
Tank monitoring is not required but considered one of several options for spill
prevention.
Netting for open tanks, modular large volume tanks, construction material and tank
bottom removal are not specifically addressed in these regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-39

Table C-11. Summary of Regulations for E&P Wastes in West Virginia
Topic Area Summary
Pit Construction and
Operation Requirements
Regulations refer to pits (with wastewater pits being the only type specified) and
centralized pits and impoundments with capacity greater than 5,000 barrels (bbl.). Permits
for specific well site work (similar to an Application for Permit to Drill in other states) are
required prior to beginning any construction, but pits do not require a special permit.
Authorization and approval from the agency is required for centralized impoundments
with a capacity of greater than 5,000 bbl. A synthetic liner is required unless an exception
is deemed appropriate based on soil analyses. Requirements include fencing, a freeboard
of 2 feet, berm specifications, run-on/run-off controls, groundwater monitoring, signage
and inspections.
Additional requirements for centralized pits include geotechnical analysis, water quality
testing, leak detection and monitoring and a minimum depth to groundwater of 20
inches.
Discharge of produced water from coalbed methane wells is included in the General
Water Pollution Control Permit and includes many conditions for water quality limits and
testing. Discharges are not allowed from conventional or horizontal wells without a
permit.
Fencing is required for pits with capacity greater than 5,000 bbl., but regulations do not
address netting for pits. West Virginia does not have regulations for noncommercial fluid
recycling pits.
Pit Closure Requirements
Regulations specify liquids removal prior to closure of pits and impoundments and a
closure schedule. In addition, inspection and sampling are required. Financial security is
included in the well bonding requirement and no special financial security is required for
pits or other waste management units.
Spill Notification
Spill notification is required when a facility discharges (1) more than 1,000 gallons into
the water of the state in a reportable discharge or (2) oil or other pollutants into the
waters of the state in two reported discharges within any twelve-month period. The oil
and gas chief is responsible for reviewing the information and issuing an order to require
any corrective action deemed necessary to protect against future spills and forward such
recommendations to the Regional Administrator for the EPA.
Corrective Action Corrective action is not specifically addressed in state regulations.
Off-site Landfills
Disposal of E&P waste is allowed in properly permitted municipal solid waste facilities. A
July 2015 WVDEP report on drill cuttings in solid waste facilities identified six solid waste
landfills currently accepting drill cuttings (WVDEP, 2015). Collected leachate from these
facilities is either processed on-site and discharged to a stream or sent to a Publicly
Owned Treatment Works (POTW) facility for processing and
discharge to a receiving stream. The report also noted that some landfills mix drill cutting
materials with municipal solid waste, and others utilize separate dedicated drill cutting
material disposal cells. On-site disposal of drill cutting materials is allowed under state
regulations, but the 2015 report indicated operators are not utilizing this option.
Testing of waste and its use as daily cover are not specifically addressed in the regulations.
Land Application
Under the General Discharge Permit (GP-WV-1-88) fresh water from centralized or
specific well pits may be discharged in accordance with the permit conditions. Prior to
discharge the water must be sampled, and it must be sprayed or irrigated so that the
vegetation and ground can absorb the discharge without runoff.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-40

Table C-11. Summary of Regulations for E&P Wastes in West Virginia
Topic Area Summary
Beneficial Use
Beneficial use of natural gas well brine is not included in oil and gas regulations but is
permitted by the West Virginia Division of Highways for roadway prewetting, anti-icing
and de-icing. The approved use is limited to the wintertime application of natural gas
well brines in order to minimize the formation of bonded snow and ice to roadway
surfaces by utilizing the melting capabilities of salt brine. Specifications and limitations
are provided in a memorandum dated 12/22/11. The use of hydraulic fracturing return
fluids associated with horizontal or vertical gas wells is not allowable under this
memorandum.
Waste Minimization/
Management
Waste minimization activities, such as closed loop drilling and recycling of produced
water, are not required.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.
NORM and TENORM
TENORM is defined and addressed in state health regulations, not oil and gas regulations.
Landfill screening is conducted prior to acceptance of all wastes, and storage requires an
annual registration form. TENORM disposal is allowed at a disposal facility with state or
NRC registration or as approved by Department of Health and Human Resources.
TENORM waste is exempt if less than 5 pCi/g.

C.12. California
In 2016, California accounted for approximately 2.8% of the nation’s oil and gas production, according
to the U.S. Energy Information Agency data. Much of California’s current production is from older,
shallow conventional wells, and about 15% is from offshore state lands. High volume hydraulic
fracturing is not common in California at this time.
E&P waste regulations in California are dispersed among many different agencies making it challenging
to develop a comprehensive review of statewide regulatory programs. The California Department of
Conservation, Division of Oil, Gas and Geothermal Resources (DOGGR) regulates oil and natural gas
production in the state. The California Environmental Protection Agency has several departments,
such as the Department of Toxic Substances Control (DTSC), the State Water Resources Control Board
(and the associated Regional Water Quality Control Boards [RWQCB]), and California Integrated
Waste Management Board, all of which may be involved in the permitting process for oil and gas
activities, with DTSC having the primary responsibility for oil and gas solid wastes managed in pits and
RWQCB managing discharges from waste units. NORM/TENORM is not specifically addressed in state
oil and gas regulations.
DOGGR statutes and regulations are current as of February 1, 2019 with various effective dates for each
section. Revision dates were not provided in the regulations, but the enacting statutes appear to include
several revisions since 2006. Regulations regarding well stimulation treatment (acidizing and hydraulic
fracturing) were added in 2015. Solid waste regulations also have varying dates of revision, including
many original regulations from 1997.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-41

A Notice of Intention is required to drill for an oil, gas, or geothermal well, and the decision-making
body is the State Oil and Gas Supervisor or his or her representative. A consolidated permit
incorporating the environmental permits granted by environmental agencies for a project may be
issued as a single permit document by the consolidated permit agency.
Unlike all the other states, California does not automatically exempt E&P wastes from RCRA subtitle
C. DTSC describes the regulatory status of E&P wastes as follows: “In general, E&P wastes that exhibit
hazardous waste characteristics are subject to regulation as hazardous waste under the statutory
authority of DTSC, except in those cases where the wastes are hazardous solely because they exhibit
the federal characteristic of toxicity” (CalEPA, 2002). Table C-12 provides a summary of the regulations
identified for E&P wastes in California.
Table C-12. Summary of Regulations for E&P Wastes in California
Topic Area Summary
Definitions
Approximately 50 definitions are provided in the oil and gas regulations Nearly half of
the definitions are included in the Well Stimulation Treatment Regulations section from
2015. Solid waste regulations include over 230 definitions.
“Sump” is defined as “an open pit or excavation serving as a receptacle for collecting
and/or storing fluids such as mud, hydrocarbons, or waste waters attendant to oil or gas
field drilling or producing operations.” Three types of sumps (pits) are defined:
(1) “Drilling Sump” means a sump used in conjunction with well drilling operations.
(2) “Evaporation sump” means a sump containing fresh or saline water which can
properly be used to store such waters for evaporation.
(3) “Operations sump” means a sump used in conjunction with an abandonment or
rework operation.
Waste Unit Location
Requirements
Specific setback values are not provided in the oil and gas regulations. Setbacks provided
in the solid waste regulations for waste management units include distances from
airports, ground rupture and rapid geologic change but not residential areas.
Location restrictions for sumps indicate that the “collection of waste water or oil shall not
be permitted in natural drainage channels. Contingency catch basins may be permitted,
but they shall be evacuated and cleaned after any spill. Unlined evaporation sumps, if
they contain harmful waters, shall not be located where they may be in communication
with freshwater-bearing aquifers.”
Regulations contain a general prohibition on pollution. “Oilfield wastes, including but not
limited to oil, water, chemicals, mud, and cement, shall be disposed of in such a manner
as not to cause damage to life, health, property, freshwater aquifers or surface waters, or
natural resources, or be a menace to public safety.” Disposal sites for oilfield wastes must
conform to State Water Resources Control Board and appropriate California Regional
Water Quality Control Board regulations.
A minimum depth to groundwater is 5 feet for waste management units (including
surface impoundments) but not oil and gas sumps specifically.
Endangered species are not specifically addressed.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-42

Table C-12. Summary of Regulations for E&P Wastes in California
Topic Area Summary
Tank Requirements
Regulations state that secondary containment at production facilities be capable of
containing the equivalent volume of the largest single piece of equipment within the
secondary containment and confine that liquid for a minimum of 72 hours.
Tank construction requirements at production facilities are not specified but regulations
infer tanks are constructed of metal, based on the associated corrosion control
requirements. Regulations allow for non-metal tanks, but they are not subject to the
testing and construction requirements for steel tanks. Steel tanks must be inspected for
corrosion at least once a month and the minimum thickness for a tank shell/wall must be
0.06 inch with a minimum bottom plate thickness ranging from 0.05 to 0.1 inch.
Construction requirements include impermeable base and if replaced, it must have a leak
detection system that will either: (1) Channel any leak beneath the tank to a location
where it can be readily observed from the outside perimeter of the tank, or (2) Accurately
detect any tank bottom leak through the use of sensors.
The Supervisor may require a tank bottom leak detection system for any tank with a
foundation that does not have an impermeable barrier
Netting, monitoring and modular large volume tanks are not specifically addressed.
Pit Construction and
Operation Requirements
As mentioned above, pits are referred to as “sumps” in California. Three sump types are
defined in the oil and gas regulations: drilling sump, evaporation sump and operations
sump. The permit request form is entitled “Notice of Intention” and is required for the
well, not sumps specifically.
The following prohibitions were noted in the oil and gas regulations with regards to waste
disposal which may apply to sumps (pits):
• Open unlined channels and ditches shall not be used to transport waste water which
is harmful to underlying freshwater deposits. Oil or water containing oil shall not be
transported in open unlined channels or ditches unless provisions are made so that
they are not a hazard as determined by the Supervisor.
• Dumping harmful chemicals where subsequent meteoric waters might wash
significant quantities into freshwaters shall be prohibited. Drilling mud shall not be
permanently disposed of into open pits. Cement slurry or dry cement shall not be
disposed of on the surface.
Sumps must be enclosed according to different specifications based upon their location
(urban vs. non-urban). Specific details are provided for chain link fences, wire fences and
gates. Additional fencing materials may be used if approved by the Supervisor. Sumps,
except operations or drilling sumps, which contain oil or a mixture of oil and water shall
be screened (netting) to the following specifications: screens should not be greater than
2-inch nominal mesh, be of sufficient strength to restrain entry of wildlife and be
supported to prevent contact with the sump fluid. Produced water ponds are regulated
by the RWQCB and may be lined or unlined or used as evaporation or percolation pits if
approved by the RWQCB.
Signage is required for the well site, not pits specifically.
Requirements for liners, leak detection monitoring, minimum depth to groundwater, run-
off/run-on controls, and groundwater monitoring were not found for sumps but were
found for waste management units, but is unclear if these regulations would be applied
to onsite E&P waste management operations. The following paragraphs summarize waste
management regulations that may apply to pits.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-43

Table C-12. Summary of Regulations for E&P Wastes in California
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Leak detection monitoring is required for waste management units and should be
conducted at least every 5 years to determine if “measurably significant” evidence of a
release has occurred.
Waste management units and their drainage control facilities should be constructed to
manage 1000-year with 24-hour precipitation (Class II) or 100-year storm with 24-hour
precipitation (Class III). These units should also be designed to withstand the maximum
credible earthquake (Class II) or at least the maximum probable earthquake (Class III).
Groundwater monitoring is required for waste management units.
Inspection frequency information was available for production facilities, not sumps or
waste management units. Aboveground production facilities shall be inspected at least
monthly for leaks and corrosion; facilities not operating properly shall be repaired or
replaced. Secondary containment berms shall be inspected monthly, and fluids, including
rainwater, shall be removed from secondary containment areas or catch basins.
Discharge permits, noncommercial fluid recycling pits and centralized pits are not
specifically addressed in the regulations.
As of January 2015, DOGGR must provide an annual inventory of unlined sumps to the
State Water Resources Control Board and the California Regional Water Quality Control
boards. Reports for produced water ponds, both lined and unlined, were available online.
In January 2019 the requirement for reporting was repealed.
Pit Closure Requirements
Oil and gas regulations state that responsibility for sump closure lies with both RWQCB
and DTSC, and DOGGR has responsibility for final site restoration. Under State Water
Quality Control Board regulations onsite sumps used for well drilling operations are
closed by either removing the wastes for offsite disposal, or removing free liquid and
covering the residual wastes, provided that representative sampling of the sump contents
show wastes to be nonhazardous. Sampling is required for waste characterization. Drilling
mud is classified as a special waste and can be disposed at a special waste landfill.
The lease restoration includes the locations of any existing or previously removed, where
known, sumps, tanks, pipelines, and facility settings. Lease restoration includes the
removal of all tanks, above-ground pipelines, debris, and other facilities and equipment.
Financial security is required for the wells/site, not for pits specifically and a final
inspection is required after completion of plugging operations to determine if Division
environmental regulations (California Code of Regulations, Title 14, Subchapter 2) have
been adhered to.
Spill Notification
A spill contingency plan is required for each facility. Oil spills shall be promptly reported
by phone to the California Emergency Management Agency. Blowouts, fires, serious
accidents, and significant gas or water leaks resulting from or associated with an oil or
gas drilling or producing operation, or related facility, shall be promptly reported to the
appropriate Division district office, but no specific time frame is given.
An unauthorized release associated with well stimulation treatment requires a written
report to the Division within 5 days and notifying the Regional Water Board and any other
appropriate response entities for the location and the type of fluids involved.
Corrective Action
Corrective action for spills at well stimulation locations include clean up and remediation
of the area, and disposal of any cleanup or remediation waste, as required by all
applicable federal, state, and local laws and regulations.
Regulations indicate that financial assurance is required for spill response and corrective
action at production facilities.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-44

Table C-12. Summary of Regulations for E&P Wastes in California
Topic Area Summary
Off-site Landfills
Regulations do not clearly state which type of waste management unit may be used for
E&P waste, but Class II or Class III solid waste management units may be allowed. A waste
classification system is used to determine waste type.
Alternative cover materials may be approved for use as daily cover, but it is unclear if E&P
waste is allowed.
Land Application
Land treatment units (LTUs) are facilities where hazardous materials are applied onto or
incorporated into the soil surface so that hazardous constituents are degraded,
transformed or immobilized within the treatment zone. LTUs are a waste management
option, but it is unclear if E&P waste is allowed. Regulations for LTUs include precipitation
and drainage controls, and seismic design criteria.
Beneficial Use
Regulations and requirements for beneficial use of brine (produced water) are not
provided in the oil and gas rules, however based on documented practices by RWQCB
produced water can be reused for agricultural purposes. The RWQCBs may approve
specific requests for beneficial reuse of produced water. In 2016, four oil companies sent
oilfield produced water to four irrigation districts near Bakersfield.
https://www.waterboards.ca.gov/publications_forms/publications/factsheets/docs/prod_water_for_
crop_irrigation.pdf
Some solid waste is allowed for beneficial use at a solid waste landfill and may include
alternative daily cover, alternative intermediate cover, final cover foundation layer, liner
operations layer, leachate and landfill gas collection system, construction fill, road base,
wet weather operations pads and access roads, and soil amendments for erosion control
and landscaping. However, it is unclear if the use of E&P waste is allowed. Beneficial reuse
is restricted to those solid wastes appropriate for the specific use and must conform with
engineering and industry guidelines, as specified in the planning documents.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in the
state regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the state
regulations.
NORM and TENORM
Regulations addressing NORM/TENORM were not identified.
However, one facility (Buttonwillow Facility) was identified that accepts radionuclides (in
the decay series of U-238, U-235 and Th-232) up to 1,800 pCi/g. This facility serves oil
exploration and production companies, among other customers.

C.13. Arkansas
In 2016, Arkansas accounted for approximately 1.8% of U.S. oil and gas production including
conventional and unconventional resources according to the U.S. Energy Information Agency. The
Arkansas Oil and Gas Commission regulates oil and gas production, extraction and transportation in
the state. The Arkansas Department of Environmental Quality regulates solid and hazardous waste
disposal and water quality in the state. NORM is regulated by the Radiation Control Program under
the State Board of Health. Regulations were updated in 2009 and 2015 to include unconventional
resources in the Fayetteville Shale, Woodford Shale, Moorefield Shale and the Chattanooga Shale. Pit
regulations were updated most recently in 2012, and stimulation regulations were updated in 2017.
Table C-13 provides a summary of the regulations identified for E&P wastes in Arkansas.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-45

Table C-13. Summary of Regulations for E&P Wastes in Arkansas
Topic Area Summary
Definitions
Oil and gas regulations include approximately 100 entries and have not been updated
since 1991 rule book. Few definitions relate to E&P wastes. The following pits are defined
within the text of the oil and gas regulations: circulation pit, completion pit, emergency
pit, mud pit, reserve pit, test pit and workover pit.
Waste Unit Location
Requirements
Requirements for floodplains, surface water and groundwater are dispersed in
regulations. Prior authorization is required for pit construction in wetlands. Endangered
species are not specifically addressed in the regulations.
Setback are specified for storage tanks, such as 200 feet from an existing occupied
habitable dwelling. If the water table is less than 10 feet below the ground surface, pits
shall be constructed above ground or a closed loop system is required.
Tank Requirements
Containment dikes or other structures are required for tanks and shall have the capacity
of at least 1.5 times the largest tank the containment structure surrounds. Netting is
required for open top tanks to prevent birds and flying mammals from landing in the
tank.
Modular large volume tanks, construction materials, tank monitoring and tank bottom
removal are not specifically addressed in the regulations.
Pit Construction and
Operation Requirements
Multiple pit types are included in these regulations (circulation pit, completion pit,
emergency pit, mud pit, reserve pit, test pit and workover pit) and are covered by a
general APD permit. Liners are required and the type depends upon the pit contents. For
example, synthetic or compacted clay liners are used for reserve pits; and synthetic,
bentonite drilling mud or concrete liners may be used for mud and circulation pits.
Additional requirements for pit construction include a minimum 2 feet of freeboard and
minimum depth to groundwater of 10 feet. A stormwater erosion and sediment control
plan (or appropriate guidance document) shall be prepared (or presented) for the well
site. Inspections are not required but may be conducted when deemed necessary by the
ADEQ staff.
Requirements are not provided for leak detection/monitoring, fencing, netting,
groundwater monitoring, discharge permits, temporary pits, non-commercial fluid
recycling pits or centralized pits. Signs are required for the well and tank batteries but not
for pits and other waste management facilities.
Pit Closure Requirements
Liquids removal is required prior to pit closure. Oily-based solids must be removed, while
water-based solids can be buried in place. A schedule for pit closure, based on well type,
is provided in the regulations. While inspection is not specified, additional analytical or
disposal requirements may be required for oil-based drilling fluids. Financial security for
pits is included as part of general APD bond.
Spill Notification Spill notification is not specifically addressed in the state regulations.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
E&P waste disposal is allowed at a permitted surface disposal facility, however, oil-based
wastes must go to a Class I landfill (municipal). While testing of the waste is not required,
RCRA and TSCA waste testing may be required.
Use of E&P waste as a daily cover at landfills are not specifically addressed in the
regulations.
Land Application Disposal of water-based waste by land application is allowed with a permit. Specific
limitations/conditions and location restrictions are not included in the regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-46

Table C-13. Summary of Regulations for E&P Wastes in Arkansas
Topic Area Summary
Beneficial Use
Road spreading is an acceptable form of disposal for crude oil bottom sediments and
does not appear to be considered beneficial use. Specifications for road spreading are
provided in the regulations and indicate that the applied waste shall not have a produced
water content greater than 10% free water by volume. Information about beneficial use
of brine is not provided in the regulations.
Waste Minimization/
Management
If oil-based drilling fluids are to be used, and the location of the mud or circulation pit is
within 100 feet of a pond, lake, stream, Extraordinary Resource Waters, Ecologically
Sensitive Waterbody or Natural and Scenic Waterway, the Operator is required to use a
Closed Loop System. As noted previously, if the water table is less than 10 feet below the
ground surface, pits shall be constructed above ground or a closed loop system is
required.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.
NORM and TENORM
NORM is regulated by the Radiation Program under the Arkansas State Board of Health.
Disposal of NORM is allowed and details about the storage of NORM are provided. Waste
is exempt when concentrations are less than 5 picocuries per gram of radium-226 and/or
radium-228, 0.05% by weight of uranium or thorium, or 150 picocuries per gram of any
other NORM radionuclide, provided that these concentrations are not exceeded at any
time.

C.14. Utah
In 2016, the U.S. Energy Information Agency estimated that Utah accounted for approximately 1.2%
of the nation’s oil and gas production. Most of the production is from the northeast part of the state in
the Uinta Basin where several different conventional and unconventional resources are targeted. The
Division of Oil, Gas and Mining within the Department of Natural Resources regulates oil and natural
gas production in the state. Utah Oil and Gas has oversight responsibility for all operations for and
related to the production of oil or natural gas, disposal of salt water and oil-field wastes. The Utah
Department of Environmental Quality, Waste Management and Radiation Control Division regulates
solid and hazardous wastes. NORM/TENORM is not specifically addressed in state oil and gas
regulations.
The Utah Administrative Code (UAC) Rule 649 contains oil and gas regulations. Several sections of the
rule have been updated recently, including Section 3 (Drilling and Operating Practices updated in 2016)
which contains most of the permitting, pits, and hydraulic fracturing requirements and Section 9
(updated in 2013) contains the waste management and disposal rules including evaporation facilities,
landfarms, and other disposal facilities. Like many states, the waste management regulations
specifically exclude pits associated with underground injection wells.
Utah Division of Oil, Gas and Mining provide additional resources on ranking criteria to determine
waste containment requirements according to sensitivity level to protect the surface and near surface
environment. Table C-14 provides a summary of the regulations identified for E&P wastes in Utah.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-47

Table C-14. Summary of Regulations for E&P Wastes in Utah
Topic Area Summary
Definitions
Approximately 80 definitions are provided in the oil and gas regulations (Title R649),
including definitions for E&P waste, pit, emergency pit, disposal pit and reserve pit. "E
and P Waste" means exploration and production waste and is defined as those wastes
resulting from the drilling of and production from oil and gas wells as determined by the
EPA, prior to January 1, 1992, to be exempt from Subtitle C of the RCRA. The definition
of reserve pit is broader than many other states, and includes pits used for drilling as well
as completion and testing. Text in the regulation identifies additional types of pits
including workover and completion pits, storage pits, pipeline drip pits, and sumps.
UAC Rule 19, solid waste regulations state: "Solid waste does not include… : drilling muds,
produced waters, and other wastes associated with the exploration, development, or
production of oil, gas, or geothermal energy.”
Waste Unit Location
Requirements
Oil and gas regulations address floodplains, groundwater and surface water but do not
include endangered species. Setbacks related to the waste management units (not just
the well site) are specified. For example, “Disposal facilities shall be located a minimum
of one mile from residences or occupied buildings; not within a floodplain; not within 500
feet of a wetland, water-course or lakebed; and not in permeable soil with groundwater
less than 50 feet below the lowest elevation where waste will be placed.” A simple reading
of the definition of “disposal facility” indicates that pits used during the drilling and
completion may not be considered disposal facilities.C5
The Onsite Pit Guidance states that a pit/trench may not be constructed in fill material or
in a drainage or floodplain of flowing or intermittent streams. Depth to groundwater,
distances to surface water bodies and water wells, and population within a one-mile
radius are factors when determining pit specifications (such as construction materials and
liner requirements).
Tank Requirements
General tank requirements indicate that berms should be constructed of sufficient height
and width to contain tank contents.
Tank monitoring, netting for open tanks, modular large volume tanks, construction
material and tank bottom removal are not specifically addressed in these regulations.
Pit Construction and
Operation Requirements
Specifications and criteria for pit construction are not provided in the regulations,
however the text of the regulation states that the pits shall be located and constructed
according to the Division guidelines for onsite pits as provided on the Department web
page (the Guidance Document), which does provide some specifications and criteria.
General regulatory requirements say that pits shall be located and constructed in such a
manner as to contain fluids and not cause pollution of waters and soils. Permits for pits
are not required but a detailed description of the pit plan appears to be included as part
of the APD. The Division conducts a predrill site evaluation to help define reserve pit
location and construction requirements (including liner requirements). The Division
appears to have significant flexibility and authority to define site specific requirements
for pits.

C5) "Disposal Facility" means an injection well, pit, treatment facility or combination thereof that receives E and P Wastes for the
purpose of disposal [emphasis added]. This includes both commercial and noncommercial facilities. (R 649-1-1 Definitions)

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-48

Table C-14. Summary of Regulations for E&P Wastes in Utah
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Regulations require fencing and netting (when determined necessary). General
requirements for run-on/run-off control and secondary containment are also included.
Any intentional discharge of water requires an additional permit from the Division of
Water Quality. Freeboard requirements are only specified for evaporation ponds (two
feet).
Inspections are not required but may be conducted at the discretion of the agency. In
addition, leak detection and monitoring may be required in a permit for sensitive areas.
Signage is required for the site, not pits specifically. Regulations do not provide specific
requirements for temporary and emergency pits, or address noncommercial fluid
recycling pits or centralized pits.
Pit Closure Requirements
Regulations specify liquids and solids removal prior pit closure. Onsite pits must be closed
within one year following drilling and completion of the well, and an inspection of the
restored well site shall be conducted within 30 days of notification or as soon as weather
conditions permit. Sampling of the final pit condition is required, and financial security is
part of the well permit bond.
Disposal facilities including land farms, composting, bioremediation, solidification and
treatment facilities not associated with individual wells (either commercial or non-
commercial) require a separate bond.
Spill Notification
Incident reporting is specified for both major and minor reportable events at oil or gas
drilling, producing, transportation, gathering, or processing facility, or at any injection or
disposal facility. Major reportable events include an unauthorized release of more than
25 barrels of oil, salt water, oil field chemicals or oil field wastes; and any spill, venting, or
fire, regardless of the volume involved that occurs in a sensitive area (parks, recreation
sites, wildlife refuges, lakes, reservoirs, streams, urban or suburban areas), and require a
verbal notification within 24 hours and a written report within five days. Minor reportable
events include unauthorized release of more than 5 barrels and up to 25 barrels of oil,
salt water, oil field chemicals or oil field wastes; and require a written report within five
days.
Corrective Action
The regulations include general waste management practices that specify “operators shall
catch leaks, drips, contain spills and cleanup promptly.” Additional requirements are not
provided.
Off-site Landfills
Disposal of E&P waste is allowed at both commercial and non-commercial disposal
facilities under the oil and gas regulations, but regulations do not specifically address
offsite landfills. Utah Solid Waste regulations R315-304 allows E&P wastes to be disposed
in Industrial Solid Waste Landfills (Class IIIb).
Testing of waste and its use as daily cover are not specifically addressed in either of the
regulations groundwater monitoring at Class III landfills is required.
Land Application
E&P waste may be land applied, and details are provided in the regulations. Specifications
indicate waste should be liquid-free and applied to soil with a hydraulic conductivity no
greater than 1 x 10-6 cm/sec. Other treatment facilities, such as composting, solidifying,
other bioremediation, and water treatment, may be approved.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Based on the numerical risk ranking system for fluid containment describe above, Level I
conditions require total containment by closed-loop drilling system, concrete structure
or other type of total containment structure or material.
Produced water recycling is not required but is recommended.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-49

Table C-14. Summary of Regulations for E&P Wastes in Utah
Topic Area Summary
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.
NORM and TENORM
State oil and gas regulations do not address NORM/TENORM. General radioactive waste
regulations address NORM management only and set a disposal limit of 15 pCi/g for Ra
226.

C.15. Kansas
According to the U.S. Energy Information Agency, Kansas accounted for approximately 1% of U.S. oil
and gas production in 2016. Much of the oil and gas is produced from conventional resources but
drilling in the unconventional Mississippian Lime Play has increased over the past several years. The
Conservation Division of the Kansas Corporation Commission regulates oil and natural gas production
in the state. The Kansas Department of Health and Environment, Waste Management Division
regulates solid and hazardous waste disposal. NORM/TENORM is not specifically addressed in state oil
and gas regulations. Oil and gas regulations, including those related to pits and hydraulic fracturing,
were updated in 2009 and 2013, and solid waste regulations applicable to E&P wastes, including land-
spreading of E&P wastes, were updated in 2013. Table C-15 provides a summary of the regulations
identified for E&P wastes in Kansas.
Table C-15. Summary of Regulations for E&P Wastes in Kansas
Topic Area Summary
Definitions
Definitions in the oil and gas regulations include over 100 entries. The following pits are
covered in the oil and gas regulations: drilling pit (reserve pits and working pits), work-
over pit, emergency pit, settling pit, burn pit, and haul-off pit.
Waste Unit Location
Requirements
Overarching regulations for solid waste facilities address siting requirements for
floodplains, endangered species, surface water and groundwater. Floodplains and surface
water are also addressed in the oil and gas regulations. Exceptions may be requested for
siting emergency pits in sensitive groundwater areas.
Buffer zones are provided for disposal of drilling waste by land-spreading. For example,
land spreading must be at least 500 feet from each habitable structure and at least 100
feet from each intermittent stream.
Tank Requirements Signage is required for tanks. No other requirements for tanks are provided in these
regulations.
Pit Construction and
Operation Requirements
Permits are required for drilling pits, work-over pits, emergency pits, settling pits, burn
pits, and haul-off pits. Burn and confinement pits are defined as temporary.
Liners are necessary when the Conservation Division requires pits to be sealed; all
emergency pits must be sealed. Pit location must be 5 feet above the shallowest water
table. Freeboard varies from 12 inches (for drilling, work-over, burn and containment pits)
to 30 inches (for emergency and settling pits).
Requirements are not provided for leak detection/monitoring, fencing, netting, berm
requirements, run-on/run-off controls, groundwater monitoring, non-commercial fluid
recycling pits or centralized pits.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-50

Table C-15. Summary of Regulations for E&P Wastes in Kansas
Topic Area Summary
Pit Closure Requirements
Regulations require that pit contents be disposed prior to pit closure. Timeframe for
closure depends on the type of pit, which varies from 30 days after cessation for settling,
burn and emergency pits to 365 days after the well spud date for drilling pits. Inspection
and sampling during pit closure are not specifically addressed in the regulations, but
chloride content of the waste is required during permitting. Pit contents can be disposed
of in the annular well space, buried in place, or moved to an onsite or offsite disposal
location as approved by the director.
Financial security for pits is required as part of general APD bond.
Spill Notification Spill notification is addressed in the regulations.
Corrective Action Corrective action is addressed in the regulations.
Off-site Landfills
E&P waste disposal is allowed at a sanitary landfill, including a municipal solid waste
landfill.
Testing of waste and use as a daily cover at landfills are not specifically addressed in the
regulations.
Land Application
Disposal of drilling waste by land-spreading requires approval, and conditions for
disposal are provided in the regulations. Examples include waste characteristics (10,000
ppm limit for chloride content), as well as site characteristics (maximum slope is 8% and
the uppermost aquifer is at least 10 feet below ground surface).
Land application of E&P wastes is generally considered a disposal method, however an
exception to classify the use as beneficial may be granted by KDHE Bureau of Waste
Management with proper documentation. Water based drilling muds and cuttings are
eligible for land application but brine and completion fluids are not eligible. Prior to
application, KDHE requires information on the material to be applied as well as the
characteristics of the application area, and a soil loading analysis.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in these
regulations.
Commercial recycling and
reclamation facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.
NORM and TENORM
TENORM is not regulated in Kansas. Land spreading is an acceptable form of NORM
disposal when the maximum predicted NORM level is no more than 1.5 times the highest
NORM level found in the drilling waste samples and the maximum predicted NORM level
is no more than 370 Bq/kg (10 pCi/g).

C.16. Montana
In 2016, Montana accounted for 0.4% of the U.S. oil and gas production as indicated by the U.S. Energy
Information Agency. Wells include a large number of conventional reserves as well as unconventional
Bakken production in the eastern part of the state. The Montana Board of Oil and Gas Conservation
within the Natural Resources and Conservation Department regulates oil and natural gas production,
and Montana Department of Environmental Quality (MDEQ) solid waste regulations address
TENORM related to oil and gas production, in the state. The Montana Department of Environmental
Quality, Solid Waste Management Section regulates solid/hazardous waste. Updates to the oil and gas

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-51

regulations were made in 2009; these did not address pits and other waste management operations but
rather clarified select definitions, production tests, and reporting. Additional updates in 2011 and 2018
addressed hydraulic fracturing and well stimulation activities. Most regulations were last updated or
promulgated in 1992. As of 2018, revisions were being considered to TENORM rules in Montana. Table
C-16 provides a summary of the regulations identified for E&P wastes in Montana.
Table C-16. Summary of Regulations for E&P Wastes in Montana
Topic Area Summary
Definitions
Regulations contain 81 regulatory definitions but few related to E&P waste. The definition
of earthen pits includes reserve pits, skimming pits, settling pits, produced water pits,
percolation pits, evaporation pits, emergency pits, and workover pit.
Waste Unit Location
Requirements
Regulations are overarching for all pits with respect to floodplains and dispersed in
regulations for surface water and groundwater. Endangered species are not specifically
addressed in these regulations. Location restrictions are not provided; however,
regulations require that earthen pits or ponds that receive produced water containing
more than 15,000 ppm TDS must be constructed above the high groundwater table.
Tank Requirements The only tank requirement specified is netting for “open storage vessels.” No other tank
requirements are included in the regulations.
Pit Construction and
Operation Requirements
Permits are required for earthen pits and produced water pits with more than 15,000 ppm
TDS. Synthetic liners are required for production pits and oil/salt mud reserve pits.
Additional requirements include a minimum freeboard of 3 feet, fencing and netting, as
well as requirements for temporary pits. Signage is required as part of the well site but
not for pits specifically.
Requirements are not provided for leak detection/monitoring, minimum depth to
groundwater, berms or secondary containment, run-on/run-off controls, groundwater
monitoring, inspection, discharge permits, non-commercial fluid recycling pits or
centralized pits.
Pit Closure Requirements
Regulations specify liquids removal, solids removal and schedule for pit closure.
Inspection and sampling for pit closure are not specifically addressed. Financial security
for pit closure is a general requirement for bonding under the application for permit to
drill.
Spill Notification Spill notification is not specifically addressed in the state regulations.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
E&P waste disposal is allowed at municipal landfills and possibly other radioactive waste
facilities. Testing is only required for TENORM prior to disposal.
Use of waste as daily cover is not specifically addressed in the regulations.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Waste minimization and management activities, such as closed loop drilling and
produced water recycling, are not specifically addressed in these regulations.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-52

Table C-16. Summary of Regulations for E&P Wastes in Montana
Topic Area Summary
NORM and TENORM
TENORM is addressed by regulations for the MDEQ solid waste program. Disposal is
allowed at permitted TENORM landfills. Testing/screening is required as acceptable
radioactivity levels depend upon the permit for each facility.
Action plan/management plan and storage requirements are not specifically addressed
by these regulations.

C.17. Mississippi
According to the U.S. Energy Information Agency, Mississippi accounted for approximately 0.4% of
the nation’s oil and gas production in 2016. While some oil production comes from conventional
vertical wells, the bulk of Mississippi’s production (both oil and gas) is from the unconventional
Tuscaloosa Shale in the southern part of the state. Wells in the Tuscaloosa are deep and the play is still
in its early stages. The State Oil and Gas Board (OGB) regulates oil and natural gas production in the
state. The Department of Environmental Quality, Waste Division is responsible for management of
solid and hazardous waste. NORM related to oil and natural gas production is regulated by the Oil and
Gas Board.
Oil and Gas Conservation statutes (Title 53, Chapters 1 and 3) contain mostly administrative rules
related to permits, spacing, fees and authority of the OGB and were last updated in 2015. Statewide
Rules and Regulations (Order No. 201-51, Rules 1 through 69) contain the detailed requirements for
waste management including Rules 68 and 69 covering NORM-contaminated waste. Rule 61, relating
to berms crude and saltwater tanks was updated in 2015 and Rule 68 related to NORM was updated in
2017. The Rulebook also contains 12 rules applicable to state offshore submerged lands (OS-1 through
OS-12). Title 17 (Solid Waste) includes pertinent E&P waste definitions and authorizes the OGB to
regulate oilfield wastes. The most recent date of revision for regulations was not always clear in the
Rulebook, because the source often only referred to the original authorizing act. Table C-17 provides a
summary of the regulations identified for E&P wastes in Mississippi.
Table C-17. Summary of Regulations for E&P Wastes in Mississippi
Topic Area Summary
Definitions
Approximately 20 definitions are provided in Title 53, Chapter 1 and 36 definitions are
included in Rule 2 regarding oil and gas operations. Some rules include additional
definitions. Five types of earthen pits are discussed: temporary salt water storage pits,
emergency pits, burn pits, well test pits and drilling reserve pit (mud pits). Regulations
are often performance based (e.g. “Mud Pits used in connection with drilling operations
shall be sited and constructed so as to prevent the escape of any of the pit contents”)
and leave much of the technical requirements to the Supervisor and inspectors for
approval.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-53

Table C-17. Summary of Regulations for E&P Wastes in Mississippi
Topic Area Summary
Waste Unit Location
Requirements
Location and siting requirements for waste management units (pits and tanks) are general
in nature. No specific setback distances from surface water, groundwater, floodplains or
sensitive habitats were found in the regulations. These criteria may be specified in well
and pit permits but were unavailable for review. Groundwater and surface water are
addressed by the general requirement for non-polluting activities: “rules and regulations
are hereby promulgated to prevent waste by pollution of air, fresh waters and soils. These
rules shall be effective throughout the state of Mississippi and are for the purpose of
prevention of waste by pollution of air, fresh waters and soils." Regulations do not address
endangered species and only floodplains in NORM landfarms. Landfarming of NORM
waste cannot be within 300 feet of an occupied dwelling, within 25-year floodplain or in
an area with less than 5 feet to groundwater.
Tank Requirements
Unlike many states, Mississippi tank regulations specifically address saltwater tanks. Each
permanent oil and/or saltwater tank or battery of oil and/or saltwater tanks require a dike
(or firewall) with 150% capacity of the largest tank. No specific construction requirements
are provided, but the dike (or firewall) should be constructed of impermeable material.
Fencing is not allowed for tanks and netting is not mentioned.C6
Modular large volume tanks, tank monitoring and permits regarding tank bottom
removal are not specifically addressed in the regulations.
Pit Construction and
Operation Requirements
Construction and operation requirements are provided for earthen pits,C7 which include
temporary salt water storage pits, emergency pits, burn pits, well test pits and drilling
reserve pit (mud pits). Permits are issued for such pits, with the exception of drilling
reserve pit (mud pits), which are included in the APD. Temporary salt water storage pits
require lining with an impervious material acceptable to the Supervisor; liners are not
mentioned for other pit types.
Berm requirements and run-on/run-off controls are general stating the pit shall be
protected from surface waters by dikes and drainage ditches. Fencing is not allowed (see
footnote for tanks below).
General performance-based requirements are provided for all five types of pits, including
construction “so as to prevent the escape of any of the contents”, and maintaining fluid
levels (freeboard) of 1 to 2 feet, all pits require a sign placed conspicuously near the pit.
Inspections are not required but a representative of the State Oil and Gas Board must be
given an opportunity to inspect a pit prior to use.
Discharge permits are not required for reserve pits. Pit fluids may be discharged to the
land surface and/or streams, after notifying the Oil and Gas Board field representative, if
mud contents meet specified criteria and proper approval is secured from the
Department of Natural Resources.

C6) The regulation specifically prohibits facilities from having restricted access with fencing and either locked or unlocked gates.
The regulation explains that insuring that this agency’s Field Inspectors and other agency personnel have unrestricted access to
all oil and gas wells, tanks, tank batteries and related oil and gas exploration and production facilities on a 24-hour a day, 7- day
a week basis for inspection and regulatory enforcement purposes.
C7) The introduction of the earthen pits rule notes that earthen pits are to be phased out, unless done in accordance with the
regulations. The term earthen pit is not defined in the regulations so it is unclear if it refers to unlined pits or any excavated area
used for storage.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-54

Table C-17. Summary of Regulations for E&P Wastes in Mississippi
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Leak detection/monitoring, minimum depth to groundwater, netting, groundwater
monitoring, non-commercial fluid recycling pits and centralized pits are not specifically
addressed in the regulations.
Onshore regulations state that impervious containers be used in lieu of pits in areas where
it is impossible or impractical to construct a pit, or to protect waters or environmental
resources. Where impervious containers are used, the contents must be properly
disposed of within ninety days following usage.
Pit Closure Requirements
Liquids removal is required prior to pit closure, and solids removal is not mentioned. Pit
closure consists of removal of fluids, backfilling, leveling and compacting for all pits. A
closure schedule is only provided for Reserve Pits, which states they should be closed
within 3 months of completion of drilling. Inspections are required for Emergency Pits
within 2 weeks after the emergency period to ensure the pit contains no more than 2 feet
of water and is ready for future emergency use. Financial assurance is required for wells,
not pits specifically. Sampling is not specifically addressed in the regulations.
Spill Notification
Spill notification and corrective action are included in these regulations for offshore wells
only.C8 The offshore rules require recording the cause, size of spill and action taken. The
record must be maintained and available for inspection by the Supervisor All spills or
leakage of oil and liquid pollutants of one barrel or more must be reported orally to the
Supervisor “without delay” and then be confirmed in writing.
Corrective Action
Regulations state that corrective action should be taken immediately and in accordance
with the approved emergency plan. Modifications to plans may be conducted as directed
by the Supervisor.
Off-site Landfills
Off-site landfills are not specifically addressed in the regulations. The regulations allow
downhole disposal of mud and other deleterious substances and allow other disposal
methods to be approved by the Supervisor. Solid waste regulations exclude E&P wastes
from solid waste regulations as well as in definitions of municipal and industrial waste,
but U.S. DOE (1997) reported 10 municipal landfills that accept E&P waste.
Land Application
Land application of NORM-contaminated wastes is allowed in Mississippi, however the
rule appears to exclude NORM impacted sludge, tank bottoms, drilling muds, drill
cuttings or other materials, thus only allowing scale from equipment and NORM
contaminated soils. Waste with ambient exposure rates in excess of 600 microR per hour
cannot be land applied and the ambient exposure rate in the impacted area should not
exceed eight (8) microR per hour above background or exceed a concentration of Radium
226 or Radium 228 of 5 pCi/g above background. These values are exceeded the operator
shall take “appropriate remedial or corrective action. Land application restrictions include
distance to groundwater (five feet), proximity to the 25-year floodplain, and distance from
inhabited dwelling (300 feet).
Beneficial Use
No beneficial uses of E&P wastes such as road spreading are provided in the regulations
but solid waste regulations allow Mississippi Department of Environmental Quality to
make a determination that allows for the beneficial use of eligible nonhazardous solid
wastes in the state, if applicants make a formal request.

C8) It is unclear if the offshore spill regulations provided in OS-8 (Prevention of Waste, including Pollution, and Waste Disposal) are
also applicable to onshore wells.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-55

Table C-17. Summary of Regulations for E&P Wastes in Mississippi
Topic Area Summary
Waste Minimization/
Management
No regulations regarding waste minimization, closed loop drilling or produced water
recycling were identified.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the oil
and gas regulations. They are not explicitly addressed in the solid waste regulations.
NORM and TENORM
NORM in Mississippi is addressed by the Division of Radiological Health within the State
Department of Health, as well as Rules 68 and 69 for NORM-contaminated wastes relating
to oil and gas activities. Under the Radiation Division, NORM is exempt from regulations
if less than 5 picocuries per gram of radium - 226 or radium - 228 above background; or,
concentrations less than 30 picocuries per gram of technologically enhanced radium-226
or radium-228.
NORM disposal requires a permit, which is issued for a period of time that is “reasonably
necessary to complete the disposal activity not to exceed 5 years.” NORM waste must be
from oil and/or gas-related activities conducted within the territorial limits of the State.
Acceptable methods of NORM disposal include (1) Placement between cement plugs; (2)
Encapsulation in pipe then placed between cement plugs; (3) Mixed with gel or mud
(slurried) and placed between cement plugs; (4) Slurried then placed into a formation; (5)
Surface land spreading; (6) Subsurface land spreading; or (7) Disposal offsite at a licensed,
low level radioactive waste or NORM disposal facility.
Notification to the Supervisor is required at least 48 hours prior to beginning disposal
operations, to allow a representative to observe, inspect the operation.
Conditions for disposal by land spreading of NORM waste were described above.
Limitations for other disposal methods were not provided.
An action plan/management plan and storage requirements are not specifically
addressed in the regulations.

C.18. Michigan
In 2016, Michigan accounted for approximately 0.3% of the nation’s oil and gas production according
to data from the U.S. Energy Information Agency. Production is from a combination of historic
conventional fields and unconventional reserves including the Antrim Shale and more recent
discoveries in the deeper Collingwood and Utica shales. The Department of Environmental Quality
(DEQ), Office of Oil, Gas and Minerals Division regulates oil and natural gas production in the state.
The DEQ is also responsible for management of solid and hazardous waste, and NORM waste related
to oil and natural gas production is regulated by its Office of Waste Management and Radiological
Protection.
Oil and gas regulations include Oil and Gas Operations (Rule 324, most recently amended in 2015) and
Ionizing Radiation Rules for Radioactive Material (Rule 325, most recently amended in 2016).
Michigan DEQ developed “Cleanup and Disposal Guidelines for Sites Contaminated with Radium-226"
in November 2013. Table C-18 provides a summary of the regulations identified for E&P wastes in
Michigan.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-56

Table C-18. Summary of Regulations for E&P Wastes in Michigan
Topic Area Summary
Definitions
Approximately 50 definitions are provided in Rule 324 and 80 are included in Rule 325.
Some sections include additional definitions. Drilling mud pits are the main pit type
regulated, but flare pits and fresh water storage pits are mentioned in the regulations.
The term “earthen pit” is used in the regulations but it is not defined. Based on context it
appears to refer to unlined pits.
Waste Unit Location
Requirements
The APD requires identification of floodplains, surface waters, rivers, and endangered
species within 1,320 feet of the proposed well location but does not restrict siting based
on these criteria. An environmental assessment is required to be submitted as part of the
APD. C9 Regulations provide setback distances for siting of wells and certain equipment
(well separators, storage tanks, and treatment equipment) near public water supply wells,
but does not address surface water. There is a general requirement for oil and gas
operations to not be conducted “at a location where it is likely that a substance may
escape in a quantity sufficient to pollute the air, soil, surface waters, or groundwaters.”
Regulations do not address siting or locations relative to endangered species or
floodplains.
Tank Requirements
Surface facilities, including tanks, require a hydrogeological investigation of the facility
area to establish local background groundwater quality prior to construction. Secondary
containment (dikes or firewalls) is required and must be have a capacity 150% of a tank
or tank battery. Secondary containment areas must have a leak monitoring system of
either a groundwater monitor well or tertiary containment. Tanks that contain
hydrocarbons or brine, or both, must be elevated and placed on impervious pads or
constructed so that any leakage can be easily detected. Operators must inspect primary
and secondary containment at surface facilities (including tanks) at least once per week.
Netting for open tanks, modular large volume tanks, construction materials and permits
regarding tank bottom removal are not specifically addressed in the regulations.
Pit Construction and
Operation Requirements
Construction and operation requirements for drill mud pits are based on pit contents and
formations drilled, and permits are required. Solid salt cuttings are not allowed in pits.
Machine oil, refuse, completion and test fluids, liquid hydrocarbons, or other materials
may not be placed in lined pits. Earthen pits may not be used for E&P waste, waste oil or
tank bottoms. Impoundments for storage of fresh water (not wastes) are allowed for
hydraulic fracturing, but tanks are required for containment of all flowback fluids.
Drilling mud pits may not be constructed unless depth to groundwater is greater than 4
feet, and requirements for liners include 20-mil virgin PVC material, no seams, and large
enough to encompass the drilling mud tank, salt washer and shale shaker. Pits must have
round corners and slope of less than 20 degrees.
Leak detection and monitoring is for the well site or hydraulic fracturing operations and
not required for pits specifically.
Fencing is required if a drilling mud pit is not closed immediately after drilling completion.
Signage is required for a well or surface facility but not pits specifically. Discharge permits
are required if discharges to the air, surface waters, or groundwater of the state are likely
to occur at a surface facility.

C9) The Environmental Impact Assessment is a 3 page form (Form 7200-19) that requires information on the impacts and mitigations
for proposed drilling program and disposal of drilling wastes and the surface facilities to be use for production.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-57

Table C-18. Summary of Regulations for E&P Wastes in Michigan
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Netting, freeboard, berms, run-on/run-off controls, inspections and non-commercial fluid
recycling pits are not specifically addressed in the regulations. Centralized production
facilities are mentioned but centralized pits are not. The application process allows the
Supervisor to evaluate permit applications based on the site-specific conditions and
require any necessary controls to avoid or control pollution.
Pit Closure Requirements
Liquids removal is required prior to pit closure. Solids removal is not required, and all
drilling mud pits shall be stiffened before encapsulation, and the liner folded over the
waste prior to covering with soil. Closure specifications for flare pits are not described in
the regulations. Drilling mud pits should be closed “as soon as practical after drilling
completion but not more than 6 months after drilling completion.” Financial responsibility
or conformance bond is required for wells, not pits specifically.
Inspection and sampling during pit closure is not specifically addressed in the regulations.
Spill Notification
Spill notification requires owners to “promptly report and record all reportable losses,
spills, and releases of brine, crude oil, oil or gas field waste, products and chemicals used
in association with oil and gas exploration, production, disposal, or development.”
Corrective Action
Corrective action details should be in an approved spill or loss response and remedial
action plan that is put on file before a facility is used. Follow-up requirements after the
corrective action are not specified.
Off-site Landfills No prohibition for offsite disposal of E&P wastes was found in the Solid Waste or Oil and
Gas regulations but off-site landfilling was not specifically identified as a disposal method.
Land Application Land application of oil and gas-related wastes is not allowed in Michigan
Beneficial Use
Roadspreading of brine may be approved by the Supervisor, however brine may not be
used by the well owner and must be transferred to another party for use.
Concentration limits are provided for hydrogen sulfide, calcium and BTEX, and annual
testing of the brine source (tanks) is required.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in the
state regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the state
regulations.
NORM and TENORM
NORM wastes relating to oil and gas activities are regulated by the Department of
Environmental Quality, Waste Management and Radiological Protection Division. Oil and
gas regulations in the state do not address NORM waste.
Downhole disposal is allowed for well plugging and abandonment waste (i.e., pipe scale).
Disposal of other NORM waste depends on the concentration, and testing is required
prior to disposal. Wastes below 50 pCi/g Ra-226 may be disposed in a hazardous waste
or Type 2 landfill and wastes greater than 50 pCi/g at a licensed radioactive waste facility.
An action plan/management plan and storage requirements are not specifically
addressed in the regulations.

C.19. Virginia
In 2016, Virginia accounted for approximately 0.3% of the nation’s oil and gas production according to
data from the U.S. Energy Information Agency. All current production is from the southwest part of
the state where oil is produced from conventional reservoirs and most gas is produced from

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-58

unconventional coalbed methane wells. Virginia has the potential for future exploitation of
unconventional shale and tight gas resources. The Department of Mines and Energy regulates oil and
natural gas production in the state. The Department of Environmental Protection, along with the
Department of Mines and Energy are responsible for management of solid and hazardous waste.
TENORM waste related to oil and natural gas production is regulated by the Department of Health.
Table C-19 provides a summary of the regulations identified for E&P wastes in Virginia.
Table C-19. Summary of Regulations for E&P Wastes in Virginia
Topic Area Summary
Definitions
Approximately 90 definitions are provided in Chapter 150 of the Virginia Gas and Oil
Regulation. Specific pit types were not discussed.
Most of the oil and gas regulations reviewed in the Virginia Gas and Oil Regulation
(Chapter 150) became effective/amended in 2013 or 2016. Most of the TENORM
regulations (Sections 3470 through 3560 of Chapter 481, Virginia Radiation Protection
Regulations) were issued in September 2006 or amended in June 2008.
Waste Unit Location
Requirements
Setback and location requirements related to groundwater and surface water are only
addressed with respect to land application of pit and produced fluids. Regulations do not
address endangered species or floodplains.
Wells have a residential setback of 200 feet from an inhabited building, unless approved
by the director. There are no specific setback requirements for waste units.
Tank Requirements
Secondary containment for tanks are required to have a capacity 1-1/2 times the volume
of the largest tank, be maintained in good condition and kept free of brush, water, oil or
other fluids.
Construction details are not included, but a general requirement states that tanks should
be “designed and constructed to contain the fluids to be stored in the tanks and prevent
unauthorized discharge of fluids.” Inspections are required at least annually for tanks and
tank installations.
Netting for open tanks, modular large volume tanks and permits regarding tank bottom
removal are not specifically addressed in the regulations.
Pit Construction and
Operation Requirements
Specific pit types are not provided in the regulations, and all pits are considered
temporary. Permits are not required for pits, but are included as part of the general well
permit.
Construction requirements for pits include a liner of 10 mil or thicker high-density
polyethylene or its equivalent and a minimum freeboard of 2 feet. “Pits may not be used
as erosion and sediment control structures or storm water management structures, and
surface drainage may not be directed into a pit.” Specific secondary containment/berm
requirements are for the entire site, not pit-specific.
Fencing is required to secure the site from the public and wildlife. Signage is also required
for the site, not pits specifically.
Groundwater monitoring is required for the site, and each well permit must include a
groundwater plan that consists of initial baseline groundwater sampling and testing
followed by subsequent sampling and testing after pit installation.
Netting, minimum depth to groundwater, leak detection/monitoring, inspections,
discharge permits, noncommercial fluid recycling pits and centralized pits are not
specifically addressed in the regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-59

Table C-19. Summary of Regulations for E&P Wastes in Virginia
Topic Area Summary
Pit Closure Requirements
All free liquids must be removed prior to pit closure. Drill cuttings and solids may remain
in the on-site pit for disposal, and testing is not required. Regulations state that pits
should be reclaimed within 180 days.
Financial security is required for the site, not pits specifically. Inspections are not
specifically addressed in the regulations.
Spill Notification
If the lining or pit fail, notification should be given by the quickest available means, and
operations shall cease until the liner and pit are repaired or rebuilt. Other onsite and off-
site leaks require oral and written reporting as part of the monthly report.
Corrective Action
On-site corrective action for spills should be “consistent with the requirements of an
abatement plan, if any has been set, in a notice of violation or closure, emergency or
other order issued by the director.” Spills reported in the mothy report must include a
description of the corrective actions taken.
Off-site Landfills Disposal of E&P waste at a permitted offsite facility (including landfills) is the
recommended practice for all other solid waste from gas, oil or geophysical operations.
Land Application
Land application of oil and gas-related wastes in Virginia does not require a permit. Fluids
to be land-applied must meet groundwater criteria (alkalinity, chloride, iron, manganese,
oil and grease, pH and SAR). Site conditions, such as slope, soils and vegetation should
be considered when determining the rate and volume of land application at each site.
Fluids may not be applied if the ground is saturated, frozen or snow-covered. Fluids also
shall not be applied closer than 25 feet from highways or property lines, closer than 50
feet from surface watercourses, wetlands, natural rock outcrops, or sinkholes, closer than
100 feet from water supply wells or springs.
Beneficial Use Virginia has beneficial use regulations, which may be applicable but are not specific for
E&P waste.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in the
regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the
regulations.
NORM and TENORM
TENORM wastes relating to oil and gas activities are regulated by the Department of
Health. TENORM is exempt from such regulations if any combination of Ra-226 and Ra-
228 is less than 5 pCi/g excluding natural background. Oil and gas regulations in the state
do not address TENORM waste.
TENORM waste shall be disposed in a facility licensed under requirements for uranium
and thorium byproduct materials. Alternate methods of disposal may be authorized.
An action plan/management plan, on-site or landfill testing/screening requirements, and
storage requirements are not specifically addressed in the regulations.

C.20. Kentucky
According to the U.S. Energy Information Agency, in 2016, Kentucky accounted for approximately
0.2% of the US oil and gas production. Oil and gas production is regulated by the Kentucky Cabinet for
Energy and Environment, Department of Natural Resources, Oil & Gas Division. Wastes from oil and
gas facilities and disposal of wastes offsite are both addressed by the Kentucky Cabinet for Energy and

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-60

Environment, Department of Environmental Protection. TENORM is regulated by the Kentucky
Cabinet for Health and Family Services. Oil and gas regulations were most recently updated in 2007,
and solid waste regulations regarding exemptions for special wastes (includes E&P wastes) were
updated in 2016. Table C-20 provides a summary of the regulations identified for E&P wastes in
Kentucky.
Table C-20. Summary of Regulations for E&P Wastes in Kentucky
Topic Area Summary
Definitions
Water pollution control regulations for oil and gas facilities (401 KAR 5:090) include 29
definitions, and o not include definitions for individual pit types or definition of E&P
waste. Definitions for the following pit types are provided in the subsections of oil and
gas regulations: holding pits for produced water and drilling pits for fluids other than
produced water associated with well drilling, construction, acidizing or fracturing an oil
or gas well.
Waste Unit Location
Requirements
Overarching regulations for waste sites and facilities in the solid waste regulations
address floodplains, endangered species, surface water and groundwater. Special waste
landfills have setback requirements (for example, 100 feet from the property line or 250
feet of an intermittent or perennial stream unless a water quality certification has been
issued). Minimum depth to groundwater for waste units is not specified.
Tank Requirements Requirements for tanks are not provided in these regulations. Best management practice
includes recycling of tank bottoms as waste oil.
Pit Construction and
Operation Requirements
Holding pits and drilling pits are specified in these regulations and are covered under
permits-by-rule. Such pits may not be used for the ultimate disposal of produced waters.
Holding pits must be designed with a synthetic liner (20 mils or equivalent), a continuous
bermed area at least two feet above ground level, and a minimum freeboard of one foot.
Regulations require all surface water to be diverted away from the holding pit. Discharge
permits are required for produced water.
Groundwater monitoring is required for special waste sites and signage is required for
general well sties, however, neither is for pits specifically. Inspections for pits are not
specified, but the Cabinet may inspect any oil and gas facility.
Requirements are not provided for leak detection/monitoring, fencing, netting, minimum
depth to groundwater, temporary pits, non-commercial fluid recycling pits or centralized
pits.
Pit Closure Requirements
Oil and Gas Well Operator’s Manual (Department for Natural Resources, Division of Oil &
Gas) indicates that solid and liquid wastes shall be removed from pits prior to closure.
The Manual also provides a closure timeframe of 30 days. Details about inspection and
sampling are not included. Note: this information is based on a manual, not regulations.
A general APD bond is required for special waste landfills but not pits specifically.
Spill Notification Operators must develop and implement Spill Prevention Control and Countermeasure
plans as required, and report spills, discharges and bypasses as necessary.
Corrective Action Corrective action is not specifically addressed in the regulations.
Off-site Landfills
E&P waste is allowed at special waste landfills and other unspecified permitted facilities.
Testing of waste and use as a daily cover are not specifically addressed in the regulations.
Land Application Special waste, including E&P wastes, may be applied at landfarming or composting
facilities. An application is required.
Beneficial Use Beneficial reuse/brine spreading is not allowed.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-61

Table C-20. Summary of Regulations for E&P Wastes in Kentucky
Topic Area Summary
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in these
regulations.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.
NORM and TENORM
TENORM is regulated by the Kentucky Cabinet of Health and Family Services. Oil and gas
regulations only address the downhole disposal of TENORM. Testing/screening is
required, and waste profile/manifest is necessary for possession and transportation of
TENORM. The type of landfill, well or low-level radioactive waste disposal facility depends
on ranges of activity concentration. An activity concentration greater than 200 pCi/g of
combined Ra-226 and Ra-228 in a landfill in Kentucky shall be prohibited.

C.21. Illinois
In 2016, Illinois accounted for approximately 0.1% of the nation’s oil and gas production according to
U.S. Energy Information Agency data. Oil is produced from conventional reservoirs in the southern
part of the state, and only a small amount of gas is produced. Most production is from stripper wells,
but there is a potential for future exploration of unconventional reserves in the deep New Albany Shale.
The Department of Natural Resources, Oil and Gas Program regulates oil and natural gas production in
the state. The Illinois Environmental Protection Agency is responsible for management of solid and
hazardous waste. NORM waste related to oil and natural gas production is regulated by the Illinois
Environmental Protection Agency, Emergency Management Agency, and Central Midwest Interstate
Low-Level Radioactive Waste Commission. Table C-21 provides a summary of the regulations
identified for E&P wastes in Illinois.
Table C-21. Summary of Regulations for E&P Wastes in Illinois
Topic Area Summary
Definitions
Approximately 50 definitions are provided in Section 240.10 of Title 62 of the Illinois
Administrative Code. Additional definitions are also provided in other sections of Part 240
(The Illinois Oil and Gas Act). Several types of pits including sediment pits (used for drill
cuttings), drilling fluid pits (circulation pits) reserve pits (for drilling fluid waste storage)
and completion pits are discussed, along with tanks and concrete storage structures.
Title 62, Chapter 1, Part 240 (The Illinois Oil and Gas Act) has an amended effective date
of March 18, 2018. Part 245 (Hydraulic Fracturing Regulations) is a recent act with
extensive regulations effective November 14, 2014.
Waste Unit Location
Requirements
Concrete storage structures and tanks are prohibited within 200 feet of an existing
inhabited structure, stream, body of water or marshy land. Concrete storage structures
are also prohibited in floodplains. A permit is required for any tank, structure, measure or
device intended or used for storage of hydraulic fracturing fluid, hydraulic fracturing
flowback, or produced water within a floodplain. Protection of groundwater and surface
water from discharges are addressed in the regulations but endangered species are not.
Minimum depth to groundwater for waste management units is not specified.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-62

Table C-21. Summary of Regulations for E&P Wastes in Illinois
Topic Area Summary
Waste Unit Location
Requirements (Cont.)
Hydraulic fracturing regulations require assessment of the potential for seismic activity
and accounting for the risks in all well drilling and operations plans. If the well is in a
seismic risk zone (as defined in the regulations) the well insurance policy is required to
have a rider providing coverage against loss or claims resulting from impacts from any
aspect of the permitted operations following earthquakes of magnitude 4.5 or more.
Tank Requirements
Secondary containment (dikes) for tanks should be have a capacity 1-1/2 times the
volume of the largest tank. Construction specifications for tanks are general and indicate
materials should be compatible with the expected fluids being contained and netting is
required for tanks.
Modular large volume tanks and tank monitoring are not specifically addressed in the
regulations. Permits for tank bottom removal are not required, but haulers of liquid
oilfield wastes (including tan bottoms) must be permitted. Crude oil bottom sediments
may be disposed of in at permitted special waste landfills, injected at a permitted facility,
bioremediated by landfarming or used for road oiling on the lease (if approved).
Pit Construction and
Operation Requirements
Specific pit types include drilling, reserve, sediment, circulation, completion and
workover/plugging, and production pits, and permits are required. Pits for freshwater and
saltwater/oil drilling fluids have separate regulations.
Liners are not required for fresh water drilling pits but other pit types require a synthetic
flexible liner that is at least 30 mils in thickness and compatible with the fluid contained.
Leak detection/monitoring, fencing, netting, run-on and run-off controls, groundwater
monitoring and inspections are required. A permit is required to discharge waste onto
the surrounding land surface or into a body of water.
Minimum depth to groundwater, freeboard and berm requirements, signage, temporary
pit requirements, noncommercial fluid recycling pits and centralized pits are not
specifically addressed in the regulations.
Pit Closure Requirements
All oilfield brine and produced waters shall be removed and disposed in a Class II UIC
well. Fresh water drilling fluid wastes may be disposed of by on-site burial or surface
application in accordance with the regulations. Saltwater and oil-based muds can be
buried onsite but must be enclosed in the liner and covered with 5 feet of soil.
Pit closure inspections, sampling and financial security are not specifically addressed in
the regulations.
Spill Notification
Immediate notification is required for spills of crude oil in excess of 1 barrel, or produced
water in excess of 5 barrels, onto the surface of the land; and all crude oil spills, regardless
of amount, which enter streams, rivers, ponds, lakes, wetlands or other bodies of water.
Corrective Action
For saltwater spills water must be removed and disposed in permitted injection wells and
the area treated with lime immediately. Loading rate and tilling requirements for lime are
provided in the regulations.
Remediation requirements are presented separately for crude oil spills and produced
water spills. For saltwater spills, the Department will determine if additional remediation
action needs to be taken by the permittee, which may include flushing of the area with
freshwater, the addition of organic material (e.g., peat moss, straw), additional chemical
treatment, additional disking the soil, or soil removal.
Off-site Landfills
Liquid oilfield waste, including tank bottoms and other RCRA exempt wastes, can be
disposed of at special waste landfills. Special Waste landfills fall under the Inert Waste
landfill construction and operation requirements and are subject to stringent siting
standards and require liners, and groundwater monitoring.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-63

Table C-21. Summary of Regulations for E&P Wastes in Illinois
Topic Area Summary
Land Application
Crude oil bottom sediments may be bioremediated on-site through land spreading.
Requirements for land spreading include addition of fertilizer and lime, tilling, watering
to promote plant growth and limit runoff.
Beneficial Use
Lease road oiling is allowed and requires a permit and should not be conducted when
the ground is frozen or during precipitation events, or in areas subject to frequent
flooding. Material used for lease road oiling must contain less than 10% produced water.
Beneficial use of brine is not specifically addressed in the regulations.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in the
regulations.
Commercial Recycling and
Reclamation Facilities
The recently added hydraulic fracturing regulations recommend recycling of flowback
and produced water. Requirements for commercial water or other waste recycling
facilities are not provided in the regulations.
NORM and TENORM
NORM waste related to oil and natural gas production is regulated by the Illinois
Environmental Protection Agency, Emergency Management Agency, and Central
Midwest Interstate Low-Level Radioactive Waste Commission. Oil and gas regulations in
the state do not address NORM waste.
E&P waste is treated as a low-level radioactive waste and managed under the
Commission's Regional Management Plan. Off-site disposal of NORM waste is
permitted in non-hazardous special waste landfills if NORM is at background levels. If
greater than background levels, disposal may be required at a waste facility permitted
by the Illinois Department of Nuclear Safety. Residue containing NORM from concrete
storage structures may also require disposal at a waste facility permitted by the Illinois
Department of Nuclear Safety.
Wells targeting black shale formations (New Albany) are subject to additional
regulations due to the potential for elevated radioactivity content of the cuttings and
fluids. Permits required developing a radioactive materials management strategy to test
for and identify, manage, transport and dispose of any radioactive materials utilized or
generated during the course of operations. Testing of drill cuttings for radioactivity is
required. Drilling fluid, drilling cuttings and drilling waste from any black shale zones
that test positive for levels of radioactive contamination shall not be stored in open pits
and must be disposed of offsite at a permitted facility.

C.22. Indiana
In 2016, Indiana produced approximately 0.04% of total U.S. oil and gas production, according to the
U.S. Energy Information Agency. The Division of Oil and Gas within the Indiana Department of
Natural Resources regulates oil and natural gas production, as well as NORM related to oil and gas
production, in the state. The Indiana Department of Environmental Management regulates solid and
hazardous wastes. The oil and gas regulations, Title 29 (312 IAC 29), were promulgated in 2017. Table
C-22 provides a summary of the regulations identified for E&P wastes in Indiana.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-64

Table C-22. Summary of Regulations for E&P Wastes in Indiana
Topic Area Summary
Definitions
The oil and gas regulations include 134 definitions including many related waste
management. The definition of “E&P waste” is very general and does not reference the
RCRA exemption. Several entries relate to hydraulic fracturing, stimulation, and NORM
wastes. Definitions are provided for circulation pit, completion pit, production fluid
storage pit, reserve pit, workover pit, and concrete production fluid storage structures.
Waste Unit Location
Requirements
Requirements for facility locations in floodplains, and proximity to surface water and
groundwater are dispersed throughout the subsections in the regulations. Endangered
species are not specifically addressed in these regulations. Location restrictions are
provided (for example, pits shall not be located within 200 feet of an occupied dwelling
or a water body). Pits must also be located 3 feet above the seasonally high groundwater
table.
Tank Requirements
Indiana regulations include detailed technical and operational requirements for tank
batteries. The regulations address tank and berm design, tank construction materials, and
the treatment of storm water within secondary containment. The regulations specify
netting for open top tanks.
Pit Construction and
Operation Requirements
Regulations include definitions for the following types of pits: circulation pit, completion
pit, production fluid storage pit, reserve pit and workover pit. Permits are required for
construction of a pit in a floodway. Indiana pit and tank regulations include numerous
requirements for ”concrete production fluid storage structures” , a structure not
specifically regulated in other states in this study. Pits containing saltwater-based, oil-
based and production fluids require synthetic liners. Construction details are provided in
the regulations, and a visual inspection is required. Additional requirements for
freeboard, fencing, netting, berms, run-on/run-off controls, signage and inspections are
also included. Temporary pits are also addressed.
Requirements are not provided for groundwater monitoring, inspection, discharge
permits, non-commercial fluid recycling pits or centralized pits.
Pit Closure Requirements
Regulations specify liquids removal, liner removal and schedule for pit closure (within one
hundred twenty (120) days after conclusion of well drilling operations or sixty (60) days
of well completion operations, whichever occurs first). Inspection and sampling for pit
closure are not specifically addressed. Financial security for pit closure is a general
requirement for bonding under the application for permit to drill.
Spill Notification Spill notification is not specifically addressed in the state regulations.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
E&P waste disposal is allowed at “permitted landfills”, including municipal solid waste
landfills.
Testing of waste and its use as daily cover in municipal landfills are not specifically
addressed in the regulations.
Land Application
Water-based mud and completion fluids may be land applied. A permit is required if not
applied at the lease site. Conditions for use and location restrictions are provided in the
regulations, such as land application may not be performed during a precipitation event,
chloride content must be less than 1,000 mg/L, and the site must be located at least 100
feet from a water body.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-65

Table C-22. Summary of Regulations for E&P Wastes in Indiana
Topic Area Summary
Land Application (Cont.)

Crude oil and tank bottoms are allowed for oiling lease and county roads with a permit.
Conditions for its use are provided in the regulations. Examples specify that road oiling
shall not be conducted when the ground is frozen and the produced water content of the
crude oil tank bottoms shall not be greater than 10% free water by volume. Disposal of
oil and gas NORM on lease or county roads is prohibited.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling is noted in the regulations but it not specifically designated as a best
management practice. Closed loop systems must be maintained in a leak-free condition
when used
Produced water recycling is not required.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.
NORM and TENORM
Oil and gas NORM waste may be disposed in plugged and abandoned wells, disposed or
land applied at the lease site, or disposed at an off-site facility that is permitted to accept
such waste. Notification and disposal plan are required but a permit is not. Land
application limits indicate that after application and mixing, radioactivity concentration
in the area may not exceed five (5) pCi/g above background of Radium-226 combined
with Radium-228 or one hundred fifty (150) pCi/g above background of any other
radionuclide. Additional disposal limitations/conditions are provided in the regulations.

C.23. New York
According to the U.S. Energy Information Agency, New York accounted for approximately 0.04% of
the total US production in 2016. The New York Department of Environmental Conservation regulates
oil and gas production and facilities (Division of Mineral Resources), solid waste disposal (Division of
Materials Management) and NORM/TENORM/NARM (Division of Environmental Remediation).
Table C-23 provides a summary of the regulations identified for E&P wastes in New York.
Table C-23. Summary of Regulations for E&P Wastes in New York
Topic Area Summary
Definitions Only brine pits are discussed in the regulations. Other pit types are not defined.
Waste Unit Location
Requirements
Solid waste regulations include general requirements for siting solid waste facilities.
Overarching requirements include a general prohibition of pollution in oil and gas
operations. General well location restrictions are 100 feet from any inhabited private
dwelling house without written consent, or 150 feet from any public building and 50 feet
from a public stream, river or other body of water. Minimum depth to water is not
specified.
Tank Requirements
Tank requirements are provided for solid waste facilities, not oil and gas facilities
specifically. All tanks must be chemically compatible with the waste being stored and
inspections are required. If necessary, above ground tanks must have a secondary
containment system designed and built to contain 110% of the volume of either the
largest tank within the containment system or the total volume of all interconnected
tanks, whichever is greater. A minimum freeboard of 2 feet is required if the top of the
tank is open.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-66

Table C-23. Summary of Regulations for E&P Wastes in New York
Topic Area Summary
Tank Requirements
(Cont.)
Modular large volume tanks, netting, tank monitoring and tank bottom removal are not
specifically addressed in the regulations.
Pit Construction and
Operation Requirements
Drilling muds are not considered to be polluting fluids. The only pit type included in these
regulations is earthen pits for brine. A “watertight material” is required for brine pits;
unlined brine pits are prohibited. Permits are not required, however, the operator must
submit and receive approval for a plan for the environmentally safe and proper ultimate
disposal of fluids. A permit for discharge may be required depending on the disposal
method. Signage is necessary for the oil and gas facility, not pits specifically.
Requirements are not provided for leak detection/monitoring, fencing, netting, depth to
groundwater, freeboard, berms or secondary containment, run-on/run-off controls,
groundwater monitoring, signage, inspection, temporary pits, non-commercial fluid
recycling pits or centralized pits.
Pit Closure Requirements
Pit closure should be conducted within 45 days after cessation of drilling operations,
unless the Department approves an extension. No other details regarding pit closure are
included in the regulations. Financial security for pits is included as part of oil and gas
facility bond.
Spill Notification Spill notification is addressed in the regulations.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
E&P waste disposal is allowed at a solid waste facility. It is unclear about whether testing
of waste is required or if E&P waste may be used as daily cover, although it was noted
that the waste may not be within 10 feet of the final cover.
Land Application Land application of E&P waste is not specifically addressed in the state regulations.
Beneficial Use
Beneficial use of brine requires a written petition, and brine must meet specific criteria
for roadspreading. Specifics are provided in the regulations for its application and usage.
For example, brine application for dust control and road stabilization is prohibited
between sundown and sunrise on unpaved roads and brine may not be applied directly
to vegetation.
Waste Minimization/
Management
Waste minimization and management activities, such as closed loop drilling and
produced water recycling, are not specifically addressed in these regulations.
Commercial Recycling and
Reclamation Facilities
Commercial and stationary recycling and reclamation facilities are not specifically
addressed in these regulations.
NORM and TENORM
New York applies the term “naturally occurring and/or accelerator-produced radioactive
material (NARM)” to drill cuttings. A permit is not required for NARM disposal; however,
the disposal of TENORM is more restrictive. Storage requirements and disposal
limitations/conditions are extensive and difficult to navigate in the regulations. There is
also a specific regulation for screening if drill cuttings are being disposed.

C.24. Florida
According to U.S. Energy Information Agency data, Florida accounted for approximately 0.03% of the
nation’s oil and gas production in 2016. All production is from conventional reservoirs with most
coming from fields located near Pensacola, and a small producing area in the southern part of the state.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-67

The Department of Environmental Protection, Division of Water Resource Management, Oil and Gas
Program regulates oil and natural gas production in the state. The Division of Waste Management,
Solid Waste and Recycling Program is responsible for management of solid waste. NARM waste related
to oil and gas production is regulated by the Florida Department of Health, Radiation Control.C10 Table
C-24 provides a summary of the regulations identified for E&P wastes in Florida.
Table C-24. Summary of Regulations for E&P Wastes in Florida
Topic Area Summary
Definitions
The oil and gas regulations are relatively concise and do not provide detailed
specifications and requirements for most waste management topics. Approximately 60
definitions are provided in Chapter 62C-25 (Conservation of Oil and Gas: General). The
types of pits discussed include mud pits and reserve pits.
Most of the oil and gas rules (Sections 62C-25 through 29) were amended on March 24,
1996, with a few sections being amended since. Section 64E-5.101 (Definitions) in Control
of Radiation Hazards was published on December 26, 2013.
Waste Unit Location
Requirements
Location restrictions (residential and environmental setbacks) and minimum depth to
groundwater are not specifically addressed in the oil and gas regulations for any waste
management units. Groundwater, surface water and endangered species are not
specifically addressed in the oil and gas regulations.
Solid waste regulations state “A landfill or solid waste disposal unit shall not be located
in the 100-year floodplain where it will restrict the flow of the 100-year flood, reduce the
temporary water storage capacity of the floodplain unless compensating storage is
provided, or result in a washout of solid waste.”
Tank Requirements
There are few technical requirements for tanks in the regulations. Secondary containment
must be two times the capacity of the tank. General construction requirements indicate
materials should be “relatively impermeable and of sufficient size and strength.”
Netting, modular large volume tanks and removal of tank bottoms are not specifically
addressed. A general requirement for operating facilities includes monitoring all
equipment and facilities to immediately detect any leak which may cause pollution.
Pit Construction and
Operation Requirements
Specific pit types addressed in the regulations include mud pits and reserve pits. Earthen
pits for active drill fluids are prohibited. Sensitive areas (including wetlands and
national/state forests and parks) require prefabricated tanks and drip pans for all waste
fluid, or reserve pits that must be either lined with impermeable material or intermittently
pumped to reduce hydrostatic head. Reserve pits should also not exceed 75% capacity
to ensure adequate freeboard. General dike requirements for sites include installation of
berms and run-on/run-off controls.
Permits and signage for pits are part of the general APD.
Leak detection/monitoring, fencing, netting, minimum depth to groundwater,
groundwater monitoring, inspections, discharge permits, temporary pit requirements,
noncommercial fluid recycling pits and centralized pits are not specifically addressed in
the regulations.

C10) Florida uses the term naturally occurring or accelerator-produced radioactive material (NARM) in regulations, but the definition
is consistent with TENORM in other states.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-68

Table C-24. Summary of Regulations for E&P Wastes in Florida
Topic Area Summary
Pit Closure Requirements
Liquids and recoverable slurry must be removed from the pit and disposed either
downhole or at a landfill.
Financial security is included in the general well bond, not for pits specifically.
Pit closure schedule, inspections, and sampling are not specifically addressed in the
regulations.
Spill Notification Spills of crude petroleum or associated fluids into the environment require immediate
notification and written confirmation for spills greater than 5 barrels.
Corrective Action Corrective actions should be immediate and conducted in accordance with Spill
Prevention and Clean Up Plan.
Off-site Landfills
Off-site disposal of E&P waste is allowed, but the type of facility is not specified.
Requirements for testing of waste and use of E&P wastes as daily cover are not specifically
addressed in the state regulations.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in the
regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the
regulations.
NORM and TENORM
Florida Department of Health defines “NARM” as any naturally occurring or accelerator-
produced radioactive material. To meet the definition of licensing state, NARM only refers
to discrete sources of NARM. Diffuse sources of NARM, which are large in volume and
low in activity, are excluded from consideration by the Conference of Radiation Control
Program Directors, Inc., for licensing state designation purposes.
Florida has comprehensive regulations for radioactive materials, but none specifically
address oil and gas or TENORM. Regulations appear to allow TENORM type materials to
be disposed at permitted facilities, however specific permitting and testing requirements
are unclear.
An action plan/management plan, on-site or landfill testing/screening and storage
requirements are not specifically addressed in the regulations.

C.25. Idaho
The U.S. Energy Information Agency estimated that Idaho accounted for approximately 0.01% of the
nation’s oil and gas production in 2016. Oil exploration has occurred in Idaho since the early 1900’s but
commercial production just started in 2016 from a small conventional gas field in southwestern Idaho.
The Idaho Department of Lands, Oil and Gas Conservation Commission regulates oil and natural gas
production in the state. The Oil and Gas Division serves as the administrative arm of the Commission.
The Department of Environmental Quality, Waste Management and Remediation Division, Solid
Waste and Hazardous Waste Programs regulate solid and hazardous waste, respectively. The
Department of Environmental Quality regulates NORM/TENORM waste related to oil and natural gas
production.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-69

Idaho oil and gas regulations underwent a major revision in 2012 in response to increased drilling
activity. Additional changes have been made as recently as 2015 which included new regulations for
pits and tanks. Department of Water Resources recently announced that it would ask the EPA to run
the Class II injection program in Idaho because it is new to the industry and is the only hydrocarbon-
producing state without a Class II program in place. Table C-25 provides a summary of the regulations
identified for E&P wastes in Idaho.
Table C-25. Summary of Regulations for E&P Wastes in Idaho
Topic Area Summary
Definitions
Approximately 60 definitions are provided in Section 010 (Definitions) of ID07, Chapter
02 – Rules Governing Conservation of Oil and Natural Gas in the State of Idaho. Pits are
defined as any excavated or constructed depression or reservoir used to contain
reserve, drilling, well treatment, produced water, or other fluids at the drill site. This
does not include enclosed, mobile, or portable tanks used to contain fluids.
Regulations for waste management provide a combination of detailed technical
specifications (pit construction, for example) and more general requirements (pit
content disposal).
Waste Unit Location
Requirements
Regulations related to siting pits near floodplains, surface water and groundwater are
dispersed in the oil and gas regulations. Solid waste regulations provide general
overarching location and siting requirements for floodplains, surface water,
groundwater and endangered species. Specific setback distances for pits are not
specifically addressed in the regulations.
Tank batteries cannot be placed in a recognized source water assessment or protection
area, or within 300 feet of existing occupied structures, water wells, canals, ditches,
natural or ordinary high water mark of surface waters, or within 50 feet of highways. Pits
located in a one hundred-year floodplain must be in conformance with any applicable
floodplain ordinances. A minimum depth to groundwater is not included in the
regulations.
Tank Requirements
Regulations state that dikes for tank batteries have a capacity of 1½ times the volume
of the largest tank and a permeability of 10-9 cm/sec.
Construction specifications, netting, monitoring, modular large volume tanks and
removal of tank bottoms are not specifically addressed.
Pit Construction and
Operation Requirements
Mud pits are specifically discussed in the oil and gas regulations. Separate requirements
are provided for short-term pits (reserve, well treatment and other pits used less than 1
year) versus long-term pits (used longer than 1 year). Separate pit permits are required
only if the pit is not included under the original APD.
Liners with a thickness of 20 mils are required for reserve, well treatment and other
short-term pits, while long-term pits require liners of 60 mils. All liners should have a
permeability of 10-9 cm/sec.
Leak detection/monitoring is required for long-term pits but not short-term ones.
Fencing is required for the well site but not pits specifically. Fencing and netting are
implied for pits based on “site-specific methods for excluding people, terrestrial
animals, and avian wildlife from the pits.”
Bermed pit walls must be a minimum of 2 feet wide at the top. Pits that have berms
more than 10 feet in height or hold 50 acre-feet of fluid must comply with dam safety
requirements. A minimum freeboard of 2 feet is required for pits.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-70

Table C-25. Summary of Regulations for E&P Wastes in Idaho
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Run-off/run-on controls and signage are required for Tier II/III solid waste facilities and
groundwater monitoring is also required for Tier III facilities, not pits specifically.
Short-term pits are considered temporary pits. The owner/operator must notify the
Department within 24 hours of an emergency situation that requires an emergency pit.
Regulations require removal of oil skims from both short term and long-term pits.
Inspections, discharge permits, noncommercial fluid recycling pits and centralized pits
are not specifically addressed in the regulations.
Pit Closure Requirements
Liquid removal is required prior to pit closure. Pit liners and accumulated solids should
be removed and testing of the solids is necessary to determine an appropriate disposal
facility. After removal of the liner and solids, the pit must be inspected by the
Department and remediated if there are signs of leakage.
All reclamation work should be completed within 12 months of plugging and
abandonment of a well or closure of other oil and gas facilities.
Bonds are required for the wells/site, not for pits specifically.
Spill Notification
Notification is required for leaks from pits. “If a pit or closed-loop system develops a
leak, or if any penetration of the pit liner occurs below the liquid’s surface, then the
owner or operator shall remove all liquid above the damage or leak line within forty-
eight (48) hours, notify the appropriate Department area office within forty-eight (48)
hours of the discovery, and repair the damage or replace the pit liner.”
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
Off-site disposal of E&P waste is not clearly stated but appears to be allowed at non-
municipal solid waste landfills (NMSWLF). Routine characterization of waste is required
at both Tier II (low risk) and Tier III (higher risk) NMSWLF facilities. Both types of
facilities have stringent design criteria and require liners and groundwater monitoring.
Use of E&P waste as daily cover is not specifically addressed.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling is described as an option to pits, but not required. Produced water
recycling is not specifically addressed in the regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the
regulations.
NORM and TENORM
Idaho Board of Environmental Quality regulates NORM/TENORM related to oil and gas
activities. Oil and gas regulations do not address NORM/TENORM.
While the regulation is not clear for NORM/TENORM, radioactive materials can be
disposed at appropriately permitted RCRA C facilities. Disposal of radioactive materials
is not allowed at a municipal solid waste landfill.
An action plan/management plan, on-site or landfill testing/screening and storage
requirements are not specifically addressed in the regulations.

C.26. Tennessee
According to the U.S. Energy Information Agency, in 2016, Tennessee accounted for approximately
0.01% of the nation’s oil and gas production. Small quantities of oil and gas are produced from both

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-71

conventional wells and new unconventional wells targeting the Chattanooga Shale. The Department
of Environment and Conservation, division of Water Resources Oil and Gas Board regulates oil and
natural gas production in the state. The Department of Environment and Conservation, Division of
Radiological Health regulates NORM/TENORM waste related to oil and natural gas production.
Chapters 0400-51 through 0400-58 contain rules for the Oil and Gas Programs and were most recently
updated in June 2013. Four sections address issues related to waste management: Definitions, Drilling,
Testing and Completion, and Production. Chapter 0400-20 (Division of Radiological Health) is dated
May 22, 2012. Table C-26 provides a summary of regulations identified for E&P wastes in Tennessee.
Table C-26. Summary of Regulations for E&P Wastes in Tennessee
Topic Area Summary
Definitions
Nearly 100 definitions are provided in Chapter 0400-51-01 (Definitions) of the Rules of
the Oil and Gas Program. Discussion of waste management addresses only tanks and pits
and is fairly brief in Chapter 0400-53-03 (Prevention of Hazards and Pollution).
Regulations address hydraulic fracturing controls and chemical disclosure.
The types of pits discussed include mud circulation pits, reserve pits and saltwater pits.
Waste Unit Location
Requirements
Overarching regulations indicate wells, pits or storage facilities in wetlands or flood-prone
areas are prohibited. Regulations for surface water are dispersed and state that a pit
cannot be within 100 feet of the normal high-water line of any stream or lake. Pits and
tanks should also be located at least 100 feet from any fire hazard or dwelling.
Endangered species are not specifically addressed in the oil and gas regulations.
While a minimum depth to groundwater is not specified, there is a general requirement
that pits should be constructed above ground where shallow groundwater may be
encountered, or closed loop drilling should be used.
Tank Requirements
Regulations provide a limited amount of detail and requirements for construction and
operation of tanks. Secondary containment is required and should be 1½ times the
capacity of the largest tank in the battery. Regulations include a diagram of an excavated
tank pad and pit containment system.
Construction requirements, netting, monitoring, modular large volume tanks and removal
of tank bottoms are not specifically addressed in the regulations.
Pit Construction and
Operation Requirements
The types of pits discussed include mud circulation and reserve pits, as well as saltwater
and fracturing fluid pits. Pits for saltwater and fracturing fluids are considered temporary
storage.
Pits require synthetic liners with a minimum thickness of 10-mil thickness (or equivalent
measures, such as clay). However, mud circulation and reserve pits require a liner of 20-
mil thickness with a 4-inch welded seam overlap. These pits also have additional
minimum requirements, such as a freeboard of 2 feet, 2:1 side slopes and berm walls at
least 2 feet wide. Only runoff from the immediate area may enter the pit.
While no specific minimum depth to groundwater is provided, regulations state “In areas
where groundwater is close enough to the surface that it will be encountered in
construction of a pit, pits shall be constructed above ground, or the operator shall use a
closed-loop system.”

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-72

Table C-26. Summary of Regulations for E&P Wastes in Tennessee
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Signage is required for the well, and groundwater monitoring (sampling drinking water
wells is done at the request of the owner, and is not pits specifically. Groundwater
monitoring is only required for hydraulically fractured wells that use more than 200,000
gallons of fluid.
Permits, leak detection/monitoring, fencing, discharge permits, noncommercial fluid
recycling pits and centralized pits are not specifically addressed in the regulations.
Pit Closure Requirements
Pits should be drained and filled within 30 days of the initial disturbance. All drilling
supplies and equipment (including liners) that are not contained and covered in the pit
shall be removed from the site.
Financial security is included in the general well permit, not for pits specifically.
Inspections and sampling are not specifically addressed in the regulations.
Spill Notification A spill of oil, saltwater, or other drilling or production associated materials requires
notification within 12 hours.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills Off-site disposal of E&P waste is not specifically mentioned in the regulations.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling is a possible alternative in wetlands but is not required. As stated
above, “In areas where groundwater is close enough to the surface that it will be
encountered in construction of a pit, pits shall be constructed above ground, or the
operator shall use a closed-loop system.”
Produced water recycling is not specifically addressed in the regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the
regulations.
NORM and TENORM
Tennessee Division of Radiological Health defines “NARM” as any naturally occurring or
accelerator-produced radioactive material. It does not include byproduct, source or
special nuclear material. Oil and gas regulations do not define NARM but rather reference
radiation regulations.
Disposal of NARM is determined on a case by case basis. ASTSWMO indicates that
disposal of NARM waste is allowed in a MSWLF if less than 30 pCi/g.
An action plan/management plan and on-site or landfill testing/screening are not
specifically addressed in the regulations.

C.27. Nevada
The U.S. Energy Information Agency data indicates that Nevada accounted for less than 0.01% of the
nation’s oil and gas production in 2016. There is no commercial gas production in Nevada and a very
small volume of oil is produced from two shallow producing areas with fewer than 20 oil fields. The
Nevada Commission on Mineral Resources, Division of Minerals, Oil and Gas – Oil and Gas Program
regulates oil and natural gas production in the state. The Department of Environmental Conservation,
Division of Environmental Protection regulates solid and hazardous waste. The Department of Health

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-73

and Human Services, Division of Public and Behavioral Health regulates NORM/TENORM waste
related to oil and natural gas production.
Nevada oil and gas regulations (Chapter 522) are clear but with limited details. For example, the only
discussion of pits is in Chapter 522.225 containing two short paragraphs without any technical
specifications. The Oil and Gas Division appears to have significant flexibility to address issues on a
site-specific basis. In 2014, the oil and gas regulations were updated to include a section on hydraulic
fracturing which provides a much greater level of detail and technical specifications. Table C-27
provides a summary of the regulations identified for E&P wastes in Nevada.
Table C-27. Summary of Regulations for E&P Wastes in Nevada
Topic Area Summary
Definitions
Approximately 36 definitions are provided in Chapter 522.010 (Definitions) and 522.700
(Hydraulic Fracturing) of Chapter 522 - Oil and Gas. Definitions are not provided for
specific pit types or wastes.
Waste Unit Location
Requirements
Oil and gas regulations do not provide location or setback requirements for pits. The only
location or setback requirement potentially related to waste management units is that
the edge of the drilling pad must not be less than 100 feet from any known perennial
water source, existing water well or existing permitted structure. Dikes or fire walls are
required around oil tanks located within the corporate limits of any city or town, where
tanks for storage are less than 500 feet from any highway or inhabited dwelling, less than
1,000 feet from any school or church. Regulations are dispersed in the solid waste
regulations and provide several location requirements. For example, Class 1 landfills are
(1) allowed within 100 feet of a floodplain but must demonstrate no impact to the
floodplain; (2) must not jeopardize existence or habitat for endangered species; (3) must
not be within 1,000 feet of surface water; and (4) must not be within 100 feet of upper
aquifer.
A residential setback is not included in the regulations.
Tank Requirements
As described above, dikes or fire walls are required around permanent tanks for under
certain conditions, but regulations provide no further details on construction operation
or protection requirements.
Tanks are required for containment of all fluids during hydraulic fracturing operations.
Water regulations are referenced for requirements.
Secondary containment requirements, construction specifications, netting, monitoring,
modular large volume tanks and removal of tank bottoms are not specifically addressed.
Pit Construction and
Operation Requirements
The following types of pits are mentioned in the oil and gas regulations: collecting pits,
reserve pits, burning pits and pits “for storage of brines.”
Unlined pits for oil, brines or oilfield waste are prohibited unless approved by the Division.
In addition, a reserve pit for drilling liquids must not be subsequently used for the
discharge of wellbore fluids during the testing of the well. Hydraulic fracturing fluids must
be stored in tanks, not pits.
The requirement for liners is inferred from the prohibition of unlined pits, however, no
specifications are provided.
Signage is required for wells, not pits specifically.
Groundwater monitoring of nearby residential wells must be sampled prior to hydraulic
fracturing (this requirement is not limited to pits).

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-74

Table C-27. Summary of Regulations for E&P Wastes in Nevada
Topic Area Summary
Pit Construction and
Operation Requirements
(Cont.)
Permits, leak detection/monitoring, fencing, netting, depth to groundwater, freeboard
and berm requirements, run-off/run-on controls, inspections, discharge permits,
temporary pits, noncommercial fluid recycling pits and centralized pits are not specifically
addressed in the regulations.
Pit Closure Requirements
Pit closure shall be conducted "as soon as weather and ground conditions permit, upon
final abandonment and completion of the plugging of any well.” As practicable, the site
should be restored to its condition when operations commenced.
Financial security is included in the general well permit, not for pits specifically. Removal
of pit contents, inspections and sampling are not specifically addressed in the regulations.
Spill Notification
Notification is required after an incident, such as a fire, lightning strike, leak, break or
overflow and should include the following information: exact location of the incident;
steps being taken to remedy the situation; and details about the amount of oil or gas
lost, destroyed or permitted to escape.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
Off-site disposal of E&P waste is not specifically mentioned in the regulations but appears
to be allowed.
Testing of waste and use as daily cover were not specifically addressed.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use is not specifically addressed in the state regulations.
Waste Minimization/
Management
Closed loop drilling and produced water recycling are not specifically addressed in the
regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the
regulations.
NORM and TENORM
NORM and TENORM in the state currently have limited regulations; it is unclear if they
are regulated under NAC 459 (Hazardous Materials). Nevada Department of Health and
Human Services has an exemption for naturally occurring radioactive material that
contains less than 5 picocuries (0.185 becquerel) of radium-226 per gram of material. Oil
and gas regulations do not address NORM/TENORM.
A licensee shall dispose of licensed radioactive material only using one of the following
methods: transfer to an authorized recipient; permitted land disposal facility; by decay in
storage; by release in effluents within the limits specified, or as otherwise approved.
An action plan/management plan, on-site or landfill testing/screening and storage
requirements are not specifically addressed in the regulations.

C.28. Missouri
In 2016, Missouri accounted for less than 0.01% of the nation’s oil and gas production according to the
U.S. Energy Information Agency. A small number of oil wells produced from shallow conventional
reservoirs, and one commercial gas well was reported in 2017. Missouri has some unconventional
reserves in coalbed methane, heavy oil and tar sands. The Department of Natural Resources, Missouri
Geological Survey is responsible, in part, for activities associated with oil and natural gas production in

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Appendix C: State Programs C-75

the state. The Department of Natural Resources, Solid Waste Management Program is responsible for
management of solid waste. NORM/TENORM is not specifically addressed in state oil and gas
regulations.
Many sections of the oil and as regulations were updated in 2016 including drilling and completion,
production and well spacing. None of these sections appear to have regulations controlling waste
management. Table C-28 provides a summary of the regulations identified for E&P wastes in Missouri.
Table C-28. Summary of Regulations for E&P Wastes in Missouri
Topic Area Text
Definitions
Approximately 70 definitions are provided in 10 CSR 50-1. No pits are defined.
Missouri regulations are relatively silent on E&P waste. No technical specifications for
waste management structures (pits, tanks, etc.) are provided. The review found no
guidance, regulations or policies addressing criteria and siting of waste units, tanks, pits.
Spill notification and corrective actions, land application, beneficial use, waste
minimization, commercial recycling or NORM/TENORM.
Waste Unit Location
Requirements Waste unit location requirements are not specifically addressed in the state regulations.
Tank Requirements Tank requirements are not specifically addressed in the state regulations.
Pit Construction and
Operation Requirements
Pit construction and operation requirements are not specifically addressed in the state
regulations.
Pit Closure Requirements Pit closure requirements are not specifically addressed in the state regulations.
Spill Notification Spill notification is not specifically addressed in the state regulations.
Corrective Action Corrective action is not specifically addressed in the state regulations.
Off-site Landfills
E&P wastes are not excluded from landfills under 10 CSR 80-3.010 Design and Operation
(3) Solid Waste Excluded); and may be allowed under (2) Solid Waste Accepted…”Only
the following solid wastes shall be accepted for disposal in a sanitary landfill: municipal
waste; bulky waste; demolition and construction wastes; brush and wood wastes; cut,
chipped, or shredded tires as defined in 10 CSR 80-8; soil; rock; concrete; related inert
solids relatively insoluble in water;
E&P waste may be considered a Special Waste “(108) Special waste means waste which
is not regulated hazardous waste, which has physical or chemical characteristics, or both,
that are different from municipal, demolition, construction and wood wastes, and which
potentially require special handling.
Land Application Land application is not specifically addressed in the state regulations.
Beneficial Use Beneficial use not specifically addressed in the state regulations.
Waste Minimization/
Management
Waste minimization and management are not specifically addressed in the state
regulations.
Commercial Recycling and
Reclamation Facilities
Commercial recycling and reclamation facilities are not specifically addressed in the state
regulations.
NORM and TENORM NORM and TENORM are not specifically addressed in the state regulations.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-76

C.29. References
CalEPA (California Environmental Protection Agency). 2002. “Oil Exploration and Production Wastes
Initiative.” Prepared by the Department of Toxic Substances Control. Sacramento, CA. May.
PADEP (Pennsylvania Department of Environmental Protection). 2018. “Office of Oil and Gas
Management: At a Glance.”
TXCEQ (Texas Commission on Environmental Quality). 2014. “Management of Oil and Gas Waste at
TCEQ Regulated Facilities.” [Power Point presentation].
U.S. DOE (United Stated Department of Energy). 1997. “Costs for Off-site Disposal of Nonhazardous
Oil Field Wastes: Salt Caverns versus Other Disposal Methods.” Prepared by Argonne National
Laboratory under Contract W-31-109-Eng-38. Argonne, IL. April.
WVDEP (West Virginia Department of Environmental Protection). 2015. “Final Report on the
Examination of Drill Cuttings and Related Environmental, Economic, and Technical Aspects
Associated with Solid Waste Facilities in West Virginia.’” Prepared by the Marshall University
Center for Environmental, Geotechnical and Applied Science. Charleston, WV. June.

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-77

Attachment C-1:
Summary of State Regulatory
Elements

[Due to the large file size, this spreadsheet is maintained as a separate file.]

Management of Exploration, Development and Production Wastes
Appendix C: State Programs C-78

Attachment C-2:
Compilation of State Regulatory
Language

[Due to the large file size, this spreadsheet is maintained as a separate file.]

Enrolled Copy H.B. 310
1 SOLID AND HAZARDOUS WASTE AMENDMENTS
2 2019 GENERAL SESSION
3 STATE OF UTAH
4 Chief Sponsor: Keven J. Stratton
5 Senate Sponsor: Keith Grover
6
7 LONG TITLE
8 General Description:
9 This bill modifies provisions related to solid and hazardous waste.
10 Highlighted Provisions:
11 This bill:
12 <modifies the definitions;
13 <clarifies role of board or director;
14 <addresses waste generated and disposed of on site; and
15 <makes technical corrections.
16 Money Appropriated in this Bill:
17 None
18 Other Special Clauses:
19 None
20 Utah Code Sections Affected:
21 AMENDS:
22 19-6-102, as last amended by Laws of Utah 2017, Chapter 281
23 19-6-104, as last amended by Laws of Utah 2015, Chapter 451
24 19-6-108, as last amended by Laws of Utah 2017, Chapter 281
25 19-6-202, as last amended by Laws of Utah 2015, Chapter 451
26 19-6-502, as last amended by Laws of Utah 2017, Chapter 281
27
28 Be it enacted by the Legislature of the state of Utah:
29 Section 1. Section 19-6-102 is amended to read:
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30 19-6-102. Definitions.
31 As used in this part:
32 (1) "Board" means the Waste Management and Radiation Control Board created in
33 Section 19-1-106.
34 (2) "Closure plan" means a plan under Section 19-6-108 to close a facility or site at
35 which the owner or operator has disposed of nonhazardous solid waste or has treated, stored, or
36 disposed of hazardous waste including, if applicable, a plan to provide postclosure care at the
37 facility or site.
38 (3) (a) "Commercial nonhazardous solid waste treatment, storage, or disposal facility"
39 means a facility that receives, for profit, nonhazardous solid waste for treatment, storage, or
40 disposal.
41 (b) "Commercial nonhazardous solid waste treatment, storage, or disposal facility"
42 does not include a facility that:
43 (i) receives waste for recycling;
44 (ii) receives waste to be used as fuel, in compliance with federal and state
45 requirements; or
46 (iii) is solely under contract with a local government within the state to dispose of
47 nonhazardous solid waste generated within the boundaries of the local government.
48 (4) "Construction waste or demolition waste":
49 (a) means waste from building materials, packaging, and rubble resulting from
50 construction, demolition, remodeling, and repair of pavements, houses, commercial buildings,
51 and other structures, and from road building and land clearing; and
52 (b) does not include:
53 (i) asbestos;
54 (ii) contaminated soils or tanks resulting from remediation or cleanup at [any] a release
55 or spill;
56 (iii) waste paints;
57 (iv) solvents;
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58 (v) sealers;
59 (vi) adhesives; or [similar]
60 (vii) hazardous or potentially hazardous materials similar to that described in
61 Subsections (4)(b)(i) through (vi).
62 [(5) "Demolition waste" has the same meaning as the definition of construction waste
63 in this section.]
64 [(6)] (5) "Director" means the director of the Division of Waste Management and
65 Radiation Control.
66 [(7)] (6) "Disposal" means the discharge, deposit, injection, dumping, spilling, leaking,
67 or placing of any solid or hazardous waste into or on [any] land or water so that the waste or
68 any constituent of the waste may enter the environment, be emitted into the air, or discharged
69 into any waters, including groundwaters.
70 [(8)] (7) "Division" means the Division of Waste Management and Radiation Control,
71 created in Subsection 19-1-105(1)(d).
72 [(9)] (8) "Generation" or "generated" means the act or process of producing
73 nonhazardous solid or hazardous waste.
74 [(10)] (9) (a) "Hazardous waste" means a solid waste or combination of solid wastes
75 other than household waste [which] that, because of its quantity, concentration, or physical,
76 chemical, or infectious characteristics may cause or significantly contribute to an increase in
77 mortality or an increase in serious irreversible or incapacitating reversible illness or may pose a
78 substantial present or potential hazard to human health or the environment when improperly
79 treated, stored, transported, disposed of, or otherwise managed.
80 (b) "Hazardous waste" does not include those wastes listed in 40 C.F.R. Sec. 261.4(b).
81 [(11)] (10) "Health facility" means [hospitals,] a:
82 (a) hospital;
83 (b) psychiatric [hospitals,] hospital;
84 (c) home health [agencies, hospices,] agency;
85 (d) hospice;
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86 (e) skilled nursing [facilities,] facility;
87 (f) intermediate care [facilities,] facility;
88 (g) intermediate care [facilities] facility for people with an intellectual disability[,];
89 (h) residential health care [facilities,] facility;
90 (i) maternity [homes] home or birthing [centers,] center;
91 (j) free standing ambulatory surgical [centers, facilities] center;
92 (k) facility owned or operated by a health maintenance [organizations, and]
93 organization;
94 (l) state renal disease treatment [centers] center, including a free standing hemodialysis
95 [units,] unit;
96 (m) the [offices of private physicians and dentists] office of a private physician or
97 dentist whether for individual or private practice[,];
98 (n) veterinary [clinics, and mortuaries] clinic; or
99 (o) mortuary.
100 [(12)] (11) "Household waste" means any waste material, including garbage, trash, and
101 sanitary wastes in septic tanks, derived from households, including single-family and
102 multiple-family residences, hotels and motels, bunk houses, ranger stations, crew quarters,
103 campgrounds, picnic grounds, and day-use recreation areas.
104 [(13)] (12) "Infectious waste" means a solid waste that contains or may reasonably be
105 expected to contain pathogens of sufficient virulence and quantity that exposure to the waste by
106 a susceptible host could result in an infectious disease.
107 [(14)] (13) "Manifest" means the form used for identifying the quantity, composition,
108 origin, routing, and destination of hazardous waste during its transportation from the point of
109 generation to the point of disposal, treatment, or storage.
110 [(15)] (14) "Mixed waste" means [any] material that is a hazardous waste as defined in
111 this chapter and is also radioactive as defined in Section 19-3-102.
112 [(16)] (15) "Modification plan" means a plan under Section 19-6-108 to modify a
113 facility or site for the purpose of disposing of nonhazardous solid waste or treating, storing, or
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114 disposing of hazardous waste.
115 [(17)] (16) "Operation plan" or "nonhazardous solid or hazardous waste operation
116 plan" means a plan or approval under Section 19-6-108, including:
117 (a) a plan to own, construct, or operate a facility or site for the purpose of transferring,
118 treating, or disposing of nonhazardous solid waste or treating, storing, or disposing of
119 hazardous waste;
120 (b) a closure plan;
121 (c) a modification plan; or
122 (d) an approval that the director is authorized to issue.
123 [(18)] (17) "Permittee" means a person who is obligated under an operation plan.
124 [(19)] (18) (a) "Solid waste" means any garbage, refuse, sludge, including sludge from
125 a waste treatment plant, water supply treatment plant, or air pollution control facility, or other
126 discarded material, including solid, liquid, semi-solid, or contained gaseous material resulting
127 from industrial, commercial, mining, or agricultural operations and from community activities
128 but does not include solid or dissolved materials in domestic sewage or in irrigation return
129 flows or discharges for which a permit is required under Title 19, Chapter 5, Water Quality
130 Act, or under the Water Pollution Control Act, 33 U.S.C. Sec. 1251 et seq.
131 (b) "Solid waste" does not include [any of the following wastes unless the waste causes
132 a public nuisance or public health hazard or is otherwise determined to be a hazardous waste]
133 metal that is:
134 [(i) certain large volume wastes, such as inert construction debris used as fill material;]
135 [(ii) drilling muds, produced waters, and other wastes associated with the exploration,
136 development, or production of oil, gas, or geothermal energy;]
137 [(iii) solid wastes from the extraction, beneficiation, and processing of ores and
138 minerals;]
139 [(iv) cement kiln dust; or]
140 [(v) metal that is:]
141 [(A)] (i) purchased as a valuable commercial commodity; and
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142 [(B)] (ii) not otherwise hazardous waste or subject to conditions of the federal
143 hazardous waste regulations, including the requirements for recyclable materials found at 40
144 C.F.R. 261.6.
145 [(20)] (19) "Solid waste management facility" means the same as that term is defined
146 in Section 19-6-502.
147 [(21)] (20) "Storage" means the actual or intended containment of solid or hazardous
148 waste either on a temporary basis or for a period of years in such a manner as not to constitute
149 disposal of the waste.
150 [(22)] (21) (a) "Transfer" means the collection of nonhazardous solid waste from a
151 permanent, fixed, supplemental collection facility for movement to a vehicle for movement to
152 an offsite nonhazardous solid waste storage or disposal facility.
153 (b) "Transfer" does not mean:
154 (i) the act of moving nonhazardous solid waste from one location to another location
155 on the site where the nonhazardous solid waste is generated; or
156 (ii) placement of nonhazardous solid waste on the site where the nonhazardous solid
157 waste is generated in preparation for movement off that site.
158 [(23)] (22) "Transportation" means the off-site movement of solid or hazardous waste
159 to any intermediate point or to any point of storage, treatment, or disposal.
160 [(24)] (23) "Treatment" means a method, technique, or process designed to change the
161 physical, chemical, or biological character or composition of any solid or hazardous waste so as
162 to neutralize the waste or render the waste nonhazardous, safer for transport, amenable for
163 recovery, amenable to storage, or reduced in volume.
164 [(25)] (24) "Underground storage tank" means a tank [which] that is regulated under
165 Subtitle I of the Resource Conservation and Recovery Act, 42 U.S.C. Sec. 6991 et seq.
166 Section 2. Section 19-6-104 is amended to read:
167 19-6-104. Powers of board -- Creation of statewide solid waste management plan.
168 (1) The board may:
169 (a) make rules in accordance with Title 63G, Chapter 3, Utah Administrative
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170 Rulemaking Act, that are necessary to implement the provisions of the Radiation Control Act;
171 (b) recommend that the director:
172 (i) issue orders necessary to enforce the provisions of the Radiation Control Act;
173 (ii) enforce the orders by appropriate administrative and judicial proceedings; or
174 (iii) institute judicial proceedings to secure compliance with this part;
175 (c) (i) hold a hearing that is not an adjudicative proceeding; or
176 (ii) appoint hearing officers to conduct a hearing that is not an adjudicative proceeding;
177 (d) accept, receive, and administer grants or other funds or gifts from public and
178 private agencies, including the federal government, for the purpose of carrying out any of the
179 functions of the Radiation Control Act; or
180 (e) order the director to impound radioactive material in accordance with Section
181 19-3-111.
182 (2) (a) The board shall promote the planning and application of pollution prevention
183 and radioactive waste minimization measures to prevent the unnecessary waste and depletion
184 of natural resources; and
185 (b) review the qualifications of, and issue certificates of approval to, individuals who:
186 (i) survey mammography equipment; or
187 (ii) oversee quality assurance practices at mammography facilities.
188 (3) The board shall:
189 (a) survey solid and hazardous waste generation and management practices within this
190 state and, after public hearing and after providing opportunities for comment by local
191 governmental entities, industry, and other interested persons, prepare and revise, as necessary, a
192 waste management plan for the state;
193 (b) order the director to:
194 (i) issue orders necessary to effectuate the provisions of this part and rules made under
195 this part;
196 (ii) enforce the orders by administrative and judicial proceedings; or
197 (iii) initiate judicial proceedings to secure compliance with this part;
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198 (c) promote the planning and application of resource recovery systems to prevent the
199 unnecessary waste and depletion of natural resources;
200 (d) meet the requirements of federal law related to solid and hazardous wastes to insure
201 that the solid and hazardous wastes program provided for in this part is qualified to assume
202 primacy from the federal government in control over solid and hazardous waste;
203 (e) (i) require any facility, including those listed in Subsection (3)(e)(ii), [that is
204 intended for disposing of nonhazardous solid waste or wastes listed in Subsection (3)(e)(ii)(B)]
205 to submit plans, specifications, and other information required by the board to the [board]
206 director prior to construction, modification, installation, or establishment of a facility to allow
207 the [board] director to determine whether the proposed construction, modification, installation,
208 or establishment of the facility will be in accordance with rules made under this part;
209 (ii) facilities referred to in Subsection (3)(e)(i) include[: (A)] any incinerator that is
210 intended for disposing of nonhazardous solid waste; and
211 [(B) except for facilities that receive the following wastes solely for the purpose of
212 recycling, reuse, or reprocessing, any commercial facility that accepts for treatment or disposal,
213 and with the intent to make a profit: fly ash waste, bottom ash waste, slag waste, or flue gas
214 emission control waste generated primarily from the combustion of coal or other fossil fuels;
215 wastes from the extraction, beneficiation, and processing of ores and minerals; or cement kiln
216 dust wastes; and]
217 (iii) a facility referred to in Subsection (3)(e)(i) does not include a commercial facility
218 that is solely for the purpose of recycling, reuse, or reprocessing the following waste:
219 (A) fly ash waste;
220 (B) bottom ash waste;
221 (C) slag waste; or
222 (D) flue gas emission control waste generated primarily from the combustion of coal or
223 other fossil fuels;
224 (iv) a facility referred to in Subsection (3)(e)(i) does not include a facility when the
225 following waste is generated and the disposal occurs at an on-site location owned and operated
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226 by the generator of the waste:
227 (A) waste from the extraction, beneficiation, and processing of ores and minerals listed
228 in 40 C.F.R. 261.4(b)(7)(ii); or
229 (B) cement kiln dust;
230 (f) to ensure compliance with applicable statutes and regulations:
231 (i) review a settlement negotiated by the director in accordance with Subsection
232 19-6-107(3)(a) that requires a civil penalty of $25,000 or more; and
233 (ii) approve or disapprove the settlement.
234 (4) The board may:
235 (a) (i) hold a hearing that is not an adjudicative proceeding; or
236 (ii) appoint hearing officers to conduct a hearing that is not an adjudicative proceeding;
237 or
238 (b) advise, consult, cooperate with, or provide technical assistance to other agencies of
239 the state or federal government, other states, interstate agencies, or affected groups, political
240 subdivisions, industries, or other persons in carrying out the purposes of this part.
241 (5) (a) The board shall establish a comprehensive statewide waste management plan
242 [by January 1, 1994].
243 (b) The plan shall:
244 (i) incorporate the solid waste management plans submitted by the counties;
245 (ii) provide an estimate of solid waste capacity needed in the state for the next 20
246 years;
247 (iii) assess the state's ability to minimize waste and recycle;
248 (iv) evaluate solid waste treatment, disposal, and storage options, as well as solid waste
249 needs and existing capacity;
250 (v) evaluate facility siting, design, and operation;
251 (vi) review funding alternatives for solid waste management; and
252 (vii) address other solid waste management concerns that the board finds appropriate
253 for the preservation of the public health and the environment.
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254 (c) The board shall consider the economic viability of solid waste management
255 strategies prior to incorporating them into the plan and shall consider the needs of population
256 centers.
257 (d) The board shall review and modify the comprehensive statewide solid waste
258 management plan no less frequently than every five years.
259 (6) (a) The board shall determine the type of solid waste generated in the state and
260 tonnage of solid waste disposed of in the state in developing the comprehensive statewide solid
261 waste management plan.
262 (b) The board shall review and modify the inventory no less frequently than once every
263 five years.
264 (7) Subject to the limitations contained in Subsection 19-6-102 [(19)] (18)(b), the
265 board shall establish siting criteria for nonhazardous solid waste disposal facilities, including
266 incinerators.
267 (8) The board may not issue, amend, renew, modify, revoke, or terminate any of the
268 following that are subject to the authority granted to the director under Section 19-6-107:
269 (a) a permit;
270 (b) a license;
271 (c) a registration;
272 (d) a certification; or
273 (e) another administrative authorization made by the director.
274 (9) A board member may not speak or act for the board unless the board member is
275 authorized by a majority of a quorum of the board in a vote taken at a meeting of the board.
276 Section 3. Section 19-6-108 is amended to read:
277 19-6-108. New nonhazardous solid or hazardous waste operation plans for
278 facility or site -- Administrative and legislative approval required -- Exemptions from
279 legislative and gubernatorial approval -- Time periods for review -- Information required
280 -- Other conditions -- Automatic revocation of approval -- Periodic review.
281 (1) For purposes of this section, the following items shall be treated as submission of a
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282 new operation plan:
283 (a) the submission of a revised operation plan specifying a different geographic site
284 than a previously submitted plan;
285 (b) an application for modification of a commercial hazardous waste incinerator if the
286 construction or the modification would increase the hazardous waste incinerator capacity above
287 the capacity specified in the operation plan as of January 1, 1990, or the capacity specified in
288 the operation plan application as of January 1, 1990, if no operation plan approval has been
289 issued as of January 1, 1990;
290 (c) an application for modification of a commercial nonhazardous solid waste
291 incinerator if the construction of the modification would cost 50% or more of the cost of
292 construction of the original incinerator or the modification would result in an increase in the
293 capacity or throughput of the incinerator of a cumulative total of 50% above the total capacity
294 or throughput that was approved in the operation plan as of January 1, 1990, or the initial
295 approved operation plan if the initial approval is subsequent to January 1, 1990;
296 (d) an application for modification of a commercial nonhazardous solid or hazardous
297 waste treatment, storage, or disposal facility, other than an incinerator, if the modification
298 would be outside the boundaries of the property owned or controlled by the applicant, as shown
299 in the application or approved operation plan as of January 1, 1990, or the initial approved
300 operation plan if the initial approval is subsequent to January 1, 1990; or
301 (e) a submission of an operation plan to construct a facility, if previous approvals of the
302 operation plan to construct the facility have been revoked pursuant to Subsection (3)(c)(iii).
303 (2) Capacity under Subsection (1)(b) shall be calculated based on the throughput
304 tonnage specified for the trial burn in the operation plan or the operation plan application if no
305 operation plan approval has been issued as of January 1, 1990, and on annual operations of
306 7,000 hours.
307 (3) (a) (i) [No] Except as specified in Subsection (3)(a)(ii)(C), a person may not own,
308 construct, modify, or operate any facility or site for the purpose of transferring, treating, or
309 disposing of nonhazardous solid waste or treating, storing, or disposing of hazardous waste
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310 without first submitting and receiving the approval of the director for an operation plan for that
311 facility or site.
312 (ii) (A) A permittee who is the current owner of a facility or site that is subject to an
313 operation plan may submit to the director information, a report, a plan, or other request for
314 approval for a proposed activity under an operation plan:
315 (I) after obtaining the consent of any other permittee who is a current owner of the
316 facility or site; and
317 (II) without obtaining the consent of any other permittee who is not a current owner of
318 the facility or site.
319 (B) The director may not:
320 (I) withhold an approval of an operation plan requested by a permittee who is a current
321 owner of the facility or site on the grounds that another permittee who is not a current owner of
322 the facility or site has not consented to the request; or
323 (II) give an approval of an operation plan requested by a permittee who is not a current
324 owner before receiving consent of the current owner of the facility or site.
325 (C) A facility referred to in Subsection (3)(a)(i) does not include a facility when the
326 waste from the extraction, beneficiation, and processing of ores and minerals listed in 40
327 C.F.R. Sec. 261.4(b)(7)(ii), or cement kiln dust, is generated and the disposal occurs at an
328 on-site location owned and operated by the generator of the waste.
329 (b) (i) Except for facilities that receive the following wastes solely for the purpose of
330 recycling, reuse, or reprocessing, [no] a person may not own, construct, modify, or operate any
331 commercial facility that accepts for treatment or disposal, with the intent to make a profit, any
332 of the wastes listed in Subsection (3)(b)(ii) without first submitting a request to and receiving
333 the approval of the director for an operation plan for that facility site.
334 (ii) Wastes referred to in Subsection (3)(b)(i) are:
335 (A) fly ash waste, bottom ash waste, slag waste, or flue gas emission control waste
336 generated primarily from the combustion of coal or other fossil fuels;
337 (B) wastes from the extraction, beneficiation, and processing of ores and minerals; or
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338 (C) cement kiln dust wastes.
339 (c) (i) [No] A person may not construct a facility listed under Subsection (3)(c)(ii) until
340 the person receives:
341 (A) local government approval and the approval described in Subsection (3)(a);
342 (B) approval from the Legislature; and
343 (C) after receiving the approvals described in Subsections (3)(c)(i)(A) and (B),
344 approval from the governor.
345 (ii) A facility referred to in Subsection (3)(c)(i) is:
346 (A) a commercial nonhazardous solid waste disposal facility;
347 (B) except for facilities that receive the following wastes solely for the purpose of
348 recycling, reuse, or reprocessing, any commercial facility that accepts for treatment or disposal,
349 with the intent to make a profit: fly ash waste, bottom ash waste, slag waste, or flue gas
350 emission control waste generated primarily from the combustion of coal or other fossil fuels;
351 wastes from the extraction, beneficiation, and processing of ores and minerals; or cement kiln
352 dust wastes; or
353 (C) a commercial hazardous waste treatment, storage, or disposal facility.
354 (iii) The required approvals described in Subsection (3)(c)(i) for a facility described in
355 Subsection (3)(c)(ii)(A) or (B) are automatically revoked if:
356 (A) the governor's approval is received on or after May 10, 2011, and the facility is not
357 operational within five years after the day on which the governor's approval is received; or
358 (B) the governor's approval is received before May 10, 2011, and the facility is not
359 operational on or before May 10, 2016.
360 (iv) The required approvals described in Subsection (3)(c)(i) for a facility described in
361 Subsection (3)(c)(ii)(A) or (B), including the approved operation plan, are not transferrable to
362 another person for five years after the day on which the governor's approval is received.
363 (d) [No] A person need not obtain gubernatorial or legislative approval for the
364 construction of a hazardous waste facility for which an operating plan has been approved by or
365 submitted for approval to the executive secretary of the board under this section before April
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366 24, 1989, and which has been determined, on or before December 31, 1990, by the executive
367 secretary of the board to be complete, in accordance with state and federal requirements for
368 operating plans for hazardous waste facilities even if a different geographic site is subsequently
369 submitted.
370 (e) [No] A person need not obtain gubernatorial and legislative approval for the
371 construction of a commercial nonhazardous solid waste disposal facility for which an operation
372 plan has been approved by or submitted for approval to the executive secretary of the board
373 under this section on or before January 1, 1990, and which, on or before December 31, 1990,
374 the executive secretary of the board determines to be complete, in accordance with state and
375 federal requirements applicable to operation plans for nonhazardous solid waste facilities.
376 (f) Any person owning or operating a facility or site on or before November 19, 1980,
377 who has given timely notification as required by Section 3010 of the Resource Conservation
378 and Recovery Act of 1976, 42 U.S.C. Section 6921, et seq., and who has submitted a proposed
379 hazardous waste plan under this section for that facility or site, may continue to operate that
380 facility or site without violating this section until the plan is approved or disapproved under
381 this section.
382 (g) (i) The director shall suspend acceptance of further applications for a commercial
383 nonhazardous solid or hazardous waste facility upon a finding that the director cannot
384 adequately oversee existing and additional facilities for permit compliance, monitoring, and
385 enforcement.
386 (ii) The director shall report any suspension to the Natural Resources, Agriculture, and
387 Environment Interim Committee.
388 (4) The director shall review each proposed nonhazardous solid or hazardous waste
389 operation plan to determine whether that plan complies with the provisions of this part and the
390 applicable rules of the board.
391 (5) (a) If the facility is a class I or class II facility, the director shall approve or
392 disapprove that plan within 270 days from the date it is submitted.
393 (b) Within 60 days after receipt of the plans, specifications, or other information
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394 required by this section for a class I or II facility, the director shall determine whether the plan
395 is complete and contains all information necessary to process the plan for approval.
396 (c) (i) If the plan for a class I or II facility is determined to be complete, the director
397 shall issue a notice of completeness.
398 (ii) If the plan is determined by the director to be incomplete, the director shall issue a
399 notice of deficiency, listing the additional information to be provided by the owner or operator
400 to complete the plan.
401 (d) The director shall review information submitted in response to a notice of
402 deficiency within 30 days after receipt.
403 (e) The following time periods may not be included in the 270 day plan review period
404 for a class I or II facility:
405 (i) time awaiting response from the owner or operator to requests for information
406 issued by the director;
407 (ii) time required for public participation and hearings for issuance of plan approvals;
408 and
409 (iii) time for review of the permit by other federal or state government agencies.
410 (6) (a) If the facility is a class III or class IV facility, the director shall approve or
411 disapprove that plan within 365 days from the date it is submitted.
412 (b) The following time periods may not be included in the 365 day review period:
413 (i) time awaiting response from the owner or operator to requests for information
414 issued by the director;
415 (ii) time required for public participation and hearings for issuance of plan approvals;
416 and
417 (iii) time for review of the permit by other federal or state government agencies.
418 (7) If, within 365 days after receipt of a modification plan or closure plan for any
419 facility, the director determines that the proposed plan, or any part of it, will not comply with
420 applicable rules, the director shall issue an order prohibiting any action under the proposed plan
421 for modification or closure in whole or in part.
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422 (8) Any person who owns or operates a facility or site required to have an approved
423 hazardous waste operation plan under this section and who has pending a permit application
424 before the United States Environmental Protection Agency shall be treated as having an
425 approved plan until final administrative disposition of the permit application is made under this
426 section, unless the director determines that final administrative disposition of the application
427 has not been made because of the failure of the owner or operator to furnish any information
428 requested, or the facility's interim status has terminated under Section 3005 (e) of the Resource
429 Conservation and Recovery Act, 42 U.S.C. Section 6925 (e).
430 (9) The director may not approve a proposed nonhazardous solid or hazardous waste
431 operation plan unless the plan contains the information that the board requires, including:
432 (a) estimates of the composition, quantities, and concentrations of any hazardous waste
433 identified under this part and the proposed treatment, storage, or disposal of it;
434 (b) evidence that the transfer, treatment, or disposal of nonhazardous solid waste or
435 treatment, storage, or disposal of hazardous waste will not be done in a manner that may cause
436 or significantly contribute to an increase in mortality, an increase in serious irreversible or
437 incapacitating reversible illness, or pose a substantial present or potential hazard to human
438 health or the environment;
439 (c) consistent with the degree and duration of risks associated with the transfer,
440 treatment, or disposal of nonhazardous solid waste or treatment, storage, or disposal of
441 specified hazardous waste, evidence of financial responsibility in whatever form and amount
442 that the director determines is necessary to insure continuity of operation and that upon
443 abandonment, cessation, or interruption of the operation of the facility or site, all reasonable
444 measures consistent with the available knowledge will be taken to insure that the waste
445 subsequent to being treated, stored, or disposed of at the site or facility will not present a
446 hazard to the public or the environment;
447 (d) evidence that the personnel employed at the facility or site have education and
448 training for the safe and adequate handling of nonhazardous solid or hazardous waste;
449 (e) plans, specifications, and other information that the director considers relevant to
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450 determine whether the proposed nonhazardous solid or hazardous waste operation plan will
451 comply with this part and the rules of the board;
452 (f) compliance schedules, where applicable, including schedules for corrective action
453 or other response measures for releases from any solid waste management unit at the facility,
454 regardless of the time the waste was placed in the unit;
455 (g) for a proposed operation plan submitted on or after July 1, 2013, for a new solid or
456 hazardous waste facility other than a water treatment facility that treats, stores, or disposes
457 site-generated solid or hazardous waste onsite, a traffic impact study that:
458 (i) takes into consideration the safety, operation, and condition of roadways serving the
459 proposed facility; and
460 (ii) is reviewed and approved by the Department of Transportation or a local highway
461 authority, whichever has jurisdiction over each road serving the proposed facility, with the cost
462 of the review paid by the person who submits the proposed operation plan; and
463 (h) for a proposed operation plan submitted on or after July 1, 2013, for a new
464 nonhazardous solid waste facility owned or operated by a local government, financial
465 information that discloses all costs of establishing and operating the facility, including:
466 (i) land acquisition and leasing;
467 (ii) construction;
468 (iii) estimated annual operation;
469 (iv) equipment;
470 (v) ancillary structures;
471 (vi) roads;
472 (vii) transfer stations; and
473 (viii) using other operations that are not contiguous to the proposed facility but are
474 necessary to support the facility's construction and operation.
475 (10) The director may not approve a commercial nonhazardous solid or hazardous
476 waste operation plan that meets the requirements of Subsection (9) unless it contains the
477 information required by the board, including:
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478 (a) evidence that the proposed commercial facility has a proven market of
479 nonhazardous solid or hazardous waste, including:
480 (i) information on the source, quantity, and price charged for treating, storing, and
481 disposing of potential nonhazardous solid or hazardous waste in the state and regionally;
482 (ii) a market analysis of the need for a commercial facility given existing and potential
483 generation of nonhazardous solid or hazardous waste in the state and regionally; and
484 (iii) a review of other existing and proposed commercial nonhazardous solid or
485 hazardous waste facilities regionally and nationally that would compete for the treatment,
486 storage, or disposal of the nonhazardous solid or hazardous waste;
487 (b) a description of the public benefits of the proposed facility, including:
488 (i) the need in the state for the additional capacity for the management of nonhazardous
489 solid or hazardous waste;
490 (ii) the energy and resources recoverable by the proposed facility;
491 (iii) the reduction of nonhazardous solid or hazardous waste management methods,
492 which are less suitable for the environment, that would be made possible by the proposed
493 facility; and
494 (iv) whether any other available site or method for the management of hazardous waste
495 would be less detrimental to the public health or safety or to the quality of the environment;
496 and
497 (c) compliance history of an owner or operator of a proposed commercial
498 nonhazardous solid or hazardous waste treatment, storage, or disposal facility, which may be
499 applied by the director in a nonhazardous solid or hazardous waste operation plan decision,
500 including any plan conditions.
501 (11) The director may not approve a commercial nonhazardous solid or hazardous
502 waste facility operation plan unless based on the application, and in addition to the
503 determination required in Subsections (9) and (10), the director determines that:
504 (a) the probable beneficial environmental effect of the facility to the state outweighs
505 the probable adverse environmental effect; and
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506 (b) there is a need for the facility to serve industry within the state.
507 (12) Approval of a nonhazardous solid or hazardous waste operation plan may be
508 revoked, in whole or in part, if the person to whom approval of the plan has been given fails to
509 comply with that plan.
510 (13) The director shall review all approved nonhazardous solid and hazardous waste
511 operation plans at least once every five years.
512 (14) The provisions of Subsections (10) and (11) do not apply to hazardous waste
513 facilities in existence or to applications filed or pending in the department prior to April 24,
514 1989, that are determined by the executive secretary of the board on or before December 31,
515 1990, to be complete, in accordance with state and federal requirements applicable to operation
516 plans for hazardous waste facilities.
517 (15) The provisions of Subsections (9), (10), and (11) do not apply to a nonhazardous
518 solid waste facility in existence or to an application filed or pending in the department prior to
519 January 1, 1990, that is determined by the director, on or before December 31, 1990, to be
520 complete in accordance with state and federal requirements applicable to operation plans for
521 nonhazardous solid waste facilities.
522 (16) Nonhazardous solid waste generated outside of this state that is defined as
523 hazardous waste in the state where it is generated and which is received for disposal in this
524 state may not be disposed of at a nonhazardous waste disposal facility owned and operated by
525 local government or a facility under contract with a local government solely for disposal of
526 nonhazardous solid waste generated within the boundaries of the local government, unless
527 disposal is approved by the director.
528 (17) This section may not be construed to exempt any facility from applicable
529 regulation under the federal Atomic Energy Act, 42 U.S.C. Sections 2014 and 2021 through
530 2114.
531 Section 4. Section 19-6-202 is amended to read:
532 19-6-202. Definitions.
533 As used in this part:
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534 (1) "Board" means the Waste Management and Radiation Control Board created in
535 Section 19-1-106.
536 (2) "Disposal" means the final disposition of hazardous wastes into or onto the lands,
537 waters, and air of this state.
538 (3) "Hazardous wastes" means [wastes] hazardous waste as defined in Section
539 19-6-102.
540 (4) "Hazardous waste treatment, disposal, and storage facility" means a facility or site
541 used or intended to be used for the treatment, storage, or disposal of hazardous waste materials,
542 including physical, chemical, or thermal processing systems, incinerators, and secure landfills.
543 (5) "Site" means land used for the treatment, disposal, or storage of hazardous wastes.
544 (6) "Siting plan" means the state hazardous waste facilities siting plan adopted by the
545 board pursuant to Sections 19-6-204 and 19-6-205.
546 (7) "Storage" means the containment of hazardous wastes for a period of more than 90
547 days.
548 (8) "Treatment" means any method, technique, or process designed to change the
549 physical, chemical, or biological character or composition of any hazardous waste to neutralize
550 or render it nonhazardous, safer for transport, amenable to recovery or storage, convertible to
551 another usable material, or reduced in volume and suitable for ultimate disposal.
552 Section 5. Section 19-6-502 is amended to read:
553 19-6-502. Definitions.
554 As used in this part:
555 (1) "Governing body" means the governing board, commission, or council of a public
556 entity.
557 (2) "Jurisdiction" means the area within the incorporated limits of:
558 (a) a municipality;
559 (b) a special service district;
560 (c) a municipal-type service district;
561 (d) a service area; or
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562 (e) the territorial area of a county not lying within a municipality.
563 (3) "Long-term agreement" means an agreement or contract having a term of more than
564 five years but less than 50 years.
565 (4) "Municipal residential waste" means solid waste that is:
566 (a) discarded or rejected at a residence within the public entity's jurisdiction; and
567 (b) collected at or near the residence by:
568 (i) a public entity; or
569 (ii) a person with whom the public entity has as an agreement to provide solid waste
570 management.
571 (5) "Public entity" means:
572 (a) a county;
573 (b) a municipality;
574 (c) a special service district under Title 17D, Chapter 1, Special Service District Act;
575 (d) a service area under Title 17B, Chapter 2a, Part 9, Service Area Act; or
576 (e) a municipal-type service district created under Title 17, Chapter 34,
577 Municipal-Type Services to Unincorporated Areas.
578 (6) "Requirement" means an ordinance, policy, rule, mandate, or other directive that
579 imposes a legal duty on a person.
580 (7) "Residence" means an improvement to real property used or occupied as a primary
581 or secondary detached single-family dwelling.
582 (8) "Resource recovery" means the separation, extraction, recycling, or recovery of
583 usable material, energy, fuel, or heat from solid waste and the disposition of it.
584 (9) "Short-term agreement" means a contract or agreement having a term of five years
585 or less.
586 (10) (a) "Solid waste" means a putrescible or nonputrescible material or substance
587 discarded or rejected as being spent, useless, worthless, or in excess of the owner's needs at the
588 time of discard or rejection, including:
589 (i) garbage;
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590 (ii) refuse;
591 (iii) industrial and commercial waste;
592 (iv) sludge from an air or water control facility;
593 (v) rubbish;
594 (vi) ash;
595 (vii) contained gaseous material;
596 (viii) incinerator residue;
597 (ix) demolition and construction debris;
598 (x) a discarded automobile; and
599 (xi) offal.
600 (b) "Solid waste" does not include sewage or another highly diluted water carried
601 material or substance and those in gaseous form.
602 (11) "Solid waste management" means the purposeful and systematic collection,
603 transportation, storage, processing, recovery, or disposal of solid waste.
604 (12) (a) "Solid waste management facility" means a facility employed for solid waste
605 management, including:
606 (i) a transfer station;
607 (ii) a transport system;
608 (iii) a baling facility;
609 (iv) a landfill; and
610 (v) a processing system, including:
611 (A) a resource recovery facility;
612 (B) a facility for reducing solid waste volume;
613 (C) a plant or facility for compacting, or composting, of solid waste;
614 (D) an incinerator;
615 (E) a solid waste disposal, reduction, pyrolization, or conversion facility;
616 (F) a facility for resource recovery of energy consisting of:
617 (I) a facility for the production, transmission, distribution, and sale of heat and steam;
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618 (II) a facility for the generation and sale of electric energy to a public utility,
619 municipality, or other public entity that owns and operates an electric power system on March
620 15, 1982; and
621 (III) a facility for the generation, sale, and transmission of electric energy on an
622 emergency basis only to a military installation of the United States; and
623 (G) an auxiliary energy facility that is connected to a facility for resource recovery of
624 energy as described in Subsection (12)(a)(v)(F), that:
625 (I) is fueled by natural gas, landfill gas, or both;
626 (II) consists of a facility for the production, transmission, distribution, and sale of
627 supplemental heat and steam to meet all or a portion of the heat and steam requirements of a
628 military installation of the United States; and
629 (III) consists of a facility for the generation, transmission, distribution, and sale of
630 electric energy to a public utility, a municipality described in Subsection (12)(a)(v)(F)(II), or a
631 political subdivision created under Title 11, Chapter 13, Interlocal Cooperation Act.
632 (b) "Solid waste management facility" does not mean a facility that:
633 (i) accepts and processes metal, as [defined] described in Subsection
634 19-6-102[(19)](18)(b), by separating, shearing, sorting, shredding, compacting, baling, cutting,
635 or sizing to produce a principle commodity grade product of prepared scrap metal for sale or
636 use for remelting purposes provided that any byproduct or residual that would qualify as solid
637 waste is managed at a solid waste management facility; or
638 (ii) accepts and processes paper, plastic, rubber, glass, or textiles that:
639 (A) have been source-separated or otherwise diverted from the solid waste stream
640 before acceptance at the facility and that are not otherwise hazardous waste or subject to
641 conditions of federal hazardous waste regulations; and
642 (B) are reused or recycled as a valuable commercial commodity by separating,
643 shearing, sorting, shredding, compacting, baling, cutting, or sizing to produce a principle
644 commodity grade product, provided that any byproduct or residual that would qualify as solid
645 waste is managed at a solid waste management facility.
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646
STATE OF UTAH
OFFICE OF THE ATTORNEY GENERAL

SEAN D. REYES
ATTORNEY GENERAL

SPENCER E. AUSTIN
Chief Criminal Deputy
DANIEL BURTON
General Counsel
RIC CANTRELL
Chief of Staff
MELISSA A. HOLYOAK
Solicitor General
BRIAN L. TARBET
Chief Civil Deputy

ENVIRONMENT / HEALTH AND HUMAN SERVICES DIVISION • ENVIRONMENT SECTION
• TELEPHONE: [phone] • FACSIMILE: [phone] • T.D.D.: [phone] or 711
MAILING ADDRESS: P.O. BOX 140873 • SALT LAKE CITY, UTAH 84114-0873
STREET ADDRESS: 195 NORTH 1950 WEST, 2ND FLOOR SOUTHWEST • SALT LAKE CITY, UTAH 84116

MEMORANDUM

TO: Douglas J. Hansen, Director
Division of Waste Management and Radiation Control
Utah Department of Environmental Quality

Jalynn Knudsen, Assistant Director
Division of Waste Management and Radiation Control
Utah Department of Environmental Quality

FROM: Brenden K. Catt, Assistant Attorney General
Environment/Health & Human Services Division
Utah Attorney General’s Office

Bret F. Randall, Assistant Attorney General
Environment/Health & Human Services Division
Utah Attorney General’s Office

DATE: September 11, 2024

SUBJECT: Liner Requirements for E&P Waste Landfills

I. Questions Presented.

You have asked us to evaluate whether liners are required as a matter of law for landfills used to dispose of
waste associated with the exploration, development, or production of crude oil, natural gas, or geothermal energy
(“E&P waste”) as solid waste, and whether the absence of a liner requirement in the Division of Waste Management
and Radiation Control’s (“Division”) proposed E&P waste rules (the “proposed rules”)—specifically, Utah Admin.
Code R315-321 et seq.—would make the Division’s proposed rules less stringent than applicable federal law.

II. Brief Answers.

Federal law does not require liners for solid waste landfills disposing of E&P waste. The liner requirements
under the solid waste portions of the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq., and the
associated federal regulations, 40 C.F.R. § 257 and 40 C.F.R. § 258, are limited to municipal solid waste and coal
combustion residuals disposal. These federal requirements do not apply to E&P waste landfills as defined under Utah

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law and the proposed rules. The absence of an explicit liner requirement for E&P waste landfills in the Division’s
proposed rules does not make the Division’s proposed rules less stringent than federal law.

III. Executive Summary.

a. Prior to 2019, the Utah Solid and Hazardous Waste Act, Utah Code § 19-6-101 et seq., (the “Act”) excluded
E&P waste from the Act’s definition of “solid waste.”

b. In connection with the release of the Environmental Protection Agency’s (“EPA”) report finding that no
additional federal regulations were required to regulate E&P waste because state programs , including Utah’s
program, were adequate to meet the program objectives of RCRA’s solid waste program, EPA Region 8 sent
the Utah Department of Environmental Quality a letter indicating that the Act was less stringent than federal
law and should be amended because the Act excluded E&P waste from the definition of solid waste .

c. The clear implication of the EPA report and EPA Region 8 letter was, and is, that EPA expects the State of
Utah to regulate E&P waste as solid waste under the Act.

d. Since 2019, Utah has worked to regulate all E&P waste as solid waste under the Act, including through
program and regulatory improvements focused on these types of wastes.

e. On October 18, 2023, EPA Region 8 sent a letter to certain E&P waste disposal facilities in the Uinta Basin
recommending that the owners and operators implement “best practices,” including designing and constructing
landfills “per industry standard, to include appropriate composite liner systems and leak detection to ensure
the protectiveness required under part 257.” However, this letter did not explain how the “composite liner
systems” required under 40 C.F.R. § 257, Subpart D, apply to E&P waste landfills; nor did it generally explain
whether single-liner systems, double-liner systems, composite or synthetic liners, or natural or clay liners, are
required for E&P waste landfills.

f. The Division is developing rules to regulate the disposal of E&P waste in landfills. On July 11, 2024, the
Division received approval from the Waste Management and Radiation Control Board (“Board”) to proceed
with formal rulemaking.

g. The Division received comments during the rulemaking process that address the liner requirements for E&P
waste landfills. Certain comments rely on EPA’s letter dated October 18, 2023, to suggest that the Division’s
proposed rules may be less stringent than federal law because they do not require liners for E&P waste landfills.

IV. Background.

In 2019, the Utah State Legislature passed House Bill 310, which removed the exclusion of “drilling muds,
produced waters, and other wastes associated with the exploration, development, or production of oil, gas, or
geothermal energy” from the Act’s definition of solid waste. H.B. 310, 63rd Leg., Gen Sess. (Ut. 2019). This legislative
change became effective on May 14, 2019, and resulted in the Division having the obligation to enforce the Act and
the solid waste rules as to all E&P waste operations in the state. To effectuate this obligation, jurisdiction over E&P
waste facilities was required to transfer from the Division of Oil, Gas, and Mining to the Division.

The Division has coordinated with the regulated community and the Division of Oil, Gas, and Mining to
manage this jurisdictional transfer. The Division’s coordinated efforts have included holding public meetings and
individualized stakeholder meetings and issuing informational materials. Of these informational materials was an

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outline providing that the Division will “develop new rules that focus specifically on E&P Wastes to provide clarity
for industry.” DSHW-2021-026601. The Division’s proposed rules were first published for informal public
engagement in March 2024. DSHW-2024-005239. The Division received comments on the proposed rules during that
informal engagement and responded to those comments on July 3, 2024. DSHW-2024-007051. The Division sought
and received approval from the Board to proceed with formal rulemaking on July 11, 2024.

The Division held a public comment period on the proposed rules between August 1, 2024, and September 3,
2024. The public comments the Division received during this comment period primarily concern the absence of a liner
requirement for E&P waste landfills. Many of these comments rely on the EPA Region 8 letter dated October 18,
2023, as justification for applying the liner requirement under 40 C.F.R. § 257, Subpart D, to E&P waste landfills.
EPA Region 8 has yet to clarify the applicability of those regulations to E&P waste landfills.

V. Liner Analysis.

Unless otherwise determined by the Director of the Division, liners are not required for new or expanding E&P
waste landfills under proposed Utah Admin. Code R315-321 et seq. In this memorandum, we refer to liners generally
to include single-liner systems, double-liner systems, composite or synthetic liners, and natural or clay liners. The
following analysis demonstrates that federal law does not require liners, including single -liner systems, double-liner
systems, composite liners, natural liners, or otherwise, for E&P waste landfills. The Division’s proposed rules align
with federal law and are protective of human health and the environment.

a. Liners are not required for E&P waste landfills under federal law.

Liners are not required for new or expanding E&P waste landfill cells under federal law. Federal law requires
liners for two types of solid waste landfills—Coal Combustion Residuals landfills (“CCR landfills”) and municipal
solid waste landfills (“MSWLF”).
The federal CCR landfill requirements are codified under 40 C.F.R. § 257, Subpart D. Under 40 C.F.R. §
257.70(a)(1), a new or expanding CCR landfill “must be designed, constructed, operated, and maintained with either
a composite liner [. . .] or an alternative composite liner.” A CCR landfill is a landfill that receives coal combustion
residuals (“CCR”). 40 C.F.R. § 257.53. Importantly, CCR is defined as “fly ash, bottom ash, boiler, slag, and flue
gas desulfurization materials generated from burning coal for the purpose of generating electricity by electric utilities
and independent power producers.” 40 C.F.R. § 257.53. E&P waste is not CCR, and the liner requirements under 40
C.F.R. § 257, Subpart D, are inapplicable to E&P waste landfills.
The federal MSWLF unit requirements are codified under 40 C.F.R. § 258. Under 40 C.F.R. § 258.40(a)(1),
new or expanding MSWLF units “shall be constructed with a composite liner.” A MSWLF unit is “a discrete area of
land or an excavation that receives household waste, and that is not a land application unit, surface impoundment,
injection well, or waste pile.” 40 C.F.R. § 258.2. Household waste is defined as “any solid waste (including garbage,
trash, and sanitary septic tanks) derived from households.” 40 C.F.R. § 258.2. E&P waste is not household waste,
and the liner requirements under 40 C.F.R. § 258 are inapplicable to E&P waste landfills.
The liner requirements for solid waste landfills under 40 C.F.R. § 257, Subpart D, and 40 C.F.R. § 258 are
inapplicable to E&P waste landfills because E&P waste landfills may neither accept CCR nor municipal solid waste.
See Proposed Utah Admin. Code R315-321-4(4)(b).
b. The liner comments conflate solid waste surface impoundments and E&P waste landfills.

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The main purpose of a liner is to protect groundwater, and liners may be appropriate to protect groundwater
at certain solid waste facilities. For instance, leachate from a MSWLF is inevitable, and therefore a prescriptive liner
requirement is appropriate for a MSWLF. For a CCR landfill, CCR wastes are notoriously permeable and over-
saturation has led to dramatic slope failures, which, again, makes a prescriptive liner requirement appropriate for a
CCR landfill. The liner comments overlook the fact that the proposed rules create two different types of waste
disposal units based on the type of E&P waste each unit may accept.
The proposed rules require liners for solid waste surface impoundments that are used to dispose of “high
liquid” E&P waste.1 Solid waste surface impoundments may accept high liquid waste, leachate, or sludge and need
only comply with the high liquid waste management requirements under proposed Utah Admin. Code R315-303-
3(2) if a dewatering or other stabilization technique is used in association with the solid waste surface impoundment.
See Proposed Utah Admin. Code R315-301-2(75); see also Proposed Utah Admin. Code R315-322-5(5). Disposal of
high liquid E&P waste in surface impoundments requires a prescriptive double liner system because such high liquid
waste poses the greatest potential for harm to groundwater.
The waste disposed of in E&P waste landfills is fundamentally distinct from the waste disposed of in solid
waste surface impoundments. A primary limitation in the disposal of E&P wastes in landfill cells is that the waste be
relatively dry, stable, and not constitute high liquid waste. In fact, under the proposed rules, disposal of high liquid
waste in E&P landfill cells is explicitly prohibited, and high liquid wastes must be managed in a manner that is
protective of groundwater. See Proposed Utah Admin. Code R315-321-4(2)(c) (providing that owners and operators
must comply with Utah Admin. Code R315-303-3(2)); see also Utah Admin. Code R315-303-3(2) (providing that
“[t]he direct disposal of high liquid waste in landfill cells” is prohibited).
If E&P waste landfills and solid waste surface impoundments were both required to have liners, the need to
distinguish between high liquid and stabilized E&P waste would be less relevant. It is apparent that the proposed
rules are intended to create a flexible regulatory framework that protects groundwater in the event of disposal of high
liquid wastes but do not require the use of expensive liners for disposal of E&P waste that is dry and stable.
c. The Director maintains authority to require liners in certain circumstances.

The Director of the Division is the statutory “Director” under the Utah Water Quality Act (“WQA”), Utah
Code § 19-5-101 et seq., and the rules promulgated thereunder for groundwater protection at any facility licensed by
and under the jurisdiction of the Division. Utah Code § 19-5-102(6). The WQA is separate and independent from the
Act. Protection of the state’s groundwater resources is an important feature of the WQA and the associated rules
under Utah Admin. Code R317-6 et seq. Pursuant to this statutory directive, the Director has the authority,
responsibility, and regulatory tools necessary to protect groundwater through permitting, enforcement, and corrective
action, including the use of a scheme of groundwater classification and best available technology. See Utah Admin.
Code R317-6 et seq. The Director’s authority includes the duty and ability to require liners, monitoring, and other
measures necessary to protect groundwater resources for E&P landfill facilities where site conditions warrant more
restrictive groundwater protection controls.

1 See Proposed Utah Admin. Code R315-322-5(12)(e)-(f) (requiring solid waste surface impoundments to meet the liner design
standards of Utah Admin. Code R315-303-3(4) or the dual liner design standards of proposed Utah Admin. Code R315-322-5(12)(f)).

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The proposed rules include additional controls to protect groundwater. Those controls include run-on and
run-off systems, final cover, and post-closure monitoring. See Proposed Utah Admin. Code R315-321-4(3)(a), (d),
(e); see also Proposed Utah Admin. Code R315-321-4(2). Moreover, the proposed rules incorporate the existing
location standards for new or laterally expanding E&P landfill facilities.2 The proposed rules maintain the Director’s
authority to require liners in circumstances necessary to protect groundwater and ensure the long -term stability of
E&P waste landfill cells.
d. The proposed rules are intended to promote administrative convenience and efficiency.
Administrative convenience is another reason the proposed rules do not contain a prescriptive liner
requirement. Most E&P waste landfill cells are located, or are expected to be located, in arid areas of the state where
groundwater resources are not prevalent, groundwater tables are deep, and natural silts and clays provide varying
degrees of natural protection. Owners and operators of such facilities have the right under the rules to apply for
exemptions and variances from liner requirements due to site-specific conditions. Yet, at the same time, the Director
maintains full discretion to require liners under the WQA based on site-specific conditions. The current regulatory
structure is preferable to a structure where liners are always required but operators have the right to seek exemptions
and variances from the liner requirement due to site-specific conditions. In practice, the current regulatory structure
is intended to reduce the Division’s permit processing times and the resources the regulated community may require
to develop a permit application. Accordingly, the current regulatory structure benefits the Division and the regulated
community.
VI. The Board is statutorily authorized to promulgate rules that are no more stringent than federal law.
Under the Board’s rulemaking authority, the Board may not promulgate rules that are more stringent “than
the corresponding federal regulations which address the same circumstances.” Utah Code § 19-6-106(1). The Board
may promulgate rules more stringent than the corresponding federal regulations if the Board makes specific findings
after public comment and hearing and based on evidence in the record that the corresponding federal law is not
adequate to protect human health and the environment. Utah Code § 19-6-106(2). 40 C.F.R. § 257, Subpart A, is the
federal regulation that corresponds to the Division’s proposed Utah Admin. Code R315-321 et seq. Landfills are not
required to have liners under 40 C.F.R. § 257, Subpart A. We are not aware of a compelling reason to conclude that
federal law is inadequate to protect Utah’s environment, in large part because the Director may require, under the
WQA, the installation of liners and other appropriate controls to protect groundwater at E&P waste landfills where
conditions warrant such protections.
VII. Conclusion.

Based on the foregoing, the Division’s design standards for E&P waste landfills, including the absence of an
explicit liner requirement in the proposed rules for landfill cells where disposal of high liquid waste is prohibited,
align with federal law, the Director’s statutory authority under the WQA, and the distinct nature of waste accepted
by such facilities.

2 See Proposed Utah Admin. Code R315-321-3(1)(b) (providing that a new E&P waste landfill or lateral expansion of an existing E&P
waste landfill shall be subject to “the location standards in [Utah Admin. Code] R315 -302-1(2)(c) through R315-302-1(2)(f).”); Utah
Admin. Code R315-302-1(2)(e)(i)(B) (providing that a new facility or lateral expansion of an existing facility not required to install a
liner “shall be at least ten feet above the historical high level of groundwater.”).
10/7/2024
Ref: 8LCR-RC
Jalynn Knudsen
Assistant Director, Division of Waste Management and Radiation Control
Utah Department of Environmental Quality
P.O. Box 144840
Salt Lake City, Utah 84114-4840
[e-mail]
RE: Exploration and Production Waste Proposed Rules
Dear Ms. Knudsen:
This letter is in response to your letter dated September 17, 2024, regarding the rules that the Division
of Waste Management and Radiation Control has proposed for exploration and production (E&P)
waste. Based on a review of your proposed rules, we can concur that the liner requirements for E&P
waste landfills as proposed therein are not less stringent than applicable federal law.
The EPA appreciates your efforts to ensure protection of human health and the environment. The EPA
is exploring additional options to better ensure compliant and protective handling of E&P waste.
Questions regarding this letter can be addressed to my staff members: Jesse Newland 303-312-6353
([e-mail]) or Tara Hubner 303-312-6597 ([e-mail]).
Sincerely,
Amy Hensley
Branch Manager - RCRA & Chemicals Branch
Land, Chemicals and Redevelopment Division
AMY
HENSLEY
Digitally signed by AMY
HENSLEY
Date: 2024.10.07 16:50:49
-06'00'

cc: Doug Hansen, UDEQ Waste Management and Radiation Control Director: [e-mail]
Brian Speer, UDEQ Solid Waste Manager: [e-mail]