DAQ-2024-008071

Technical Memorandum

Limitations:
This document was prepared solely for Central Valley Water Reclamation Facility (CVWRF) in accordance with professional standards at the time the
services were performed. This document is not intended to be relied upon by any other party except for regulatory authorities contemplated by the
scope of work. We have relied on information or instructions provided by CVWRF and other parties and, unless otherwise expressly indicated, have
made no independent investigation as to the validity, completeness, or accuracy of such information.

451 A Street, Suite 1500
San Diego, CA 92101

T: 858.514.8822

Prepared for: Central Valley Water Reclamation Facility (CVWRF)
Project Title: RACT Analysis for the Control of NOx
Project No.: 159388
Technical Memorandum
Subject: RACT Analysis for Emission Units at CVWRF
Date: November 21, 2023
To: Bryan Mansell, Chief Engineer
From: Jason Wiser
Copy to: File

Prepared by:
Katie Dorety, Senior Associate Engineer

Reviewed by:
Jennifer Border, Principal Engineer

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1_RACT Analysis
Table of Contents
List of Tables ............................................................................................................................................... iv
Section 1: Background ................................................................................................................................ 4
1.1 Site History and Permitting Timeline .................................................................................................... 4
1.2 Attainment Status .................................................................................................................................. 4
1.3 Description of Emissions Units ............................................................................................................. 4
Section 2: RACT Analysis ............................................................................................................................. 6
2.1 JMS Digester Gas/Natural Gas Cogeneration Engines ....................................................................... 6
2.1.1 Reasonably Available Control Technologies ........................................................................ 6
2.1.2 Eliminate Technically Infeasible Control Technologies ....................................................... 7
2.1.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies ........ 7
2.1.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility ............................................................................................................................... 7
2.1.5 Select RACT ........................................................................................................................ 10
2.2 Diesel Fired Emergency Generators .................................................................................................. 10
2.2.1 Reasonably Available Control Technologies ..................................................................... 10
2.2.2 Eliminate Technically Infeasible Control Technologies .................................................... 11
2.2.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies ..... 11
2.2.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility ............................................................................................................................ 11
2.2.5 Select RACT ........................................................................................................................ 11
2.3 Waste Oil Heaters ............................................................................................................................... 11
2.3.1 Reasonably Available Control Technologies ..................................................................... 11
2.3.2 Eliminate Technically Infeasible Control Technologies .................................................... 11
2.3.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies ..... 11
2.3.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility ............................................................................................................................ 12
2.3.5 Select RACT ........................................................................................................................ 12
2.4 Digester Gas Flares ............................................................................................................................ 12
2.4.1 Reasonably Available Control Technologies ..................................................................... 12
2.4.2 Eliminate Technically Infeasible Control Technologies .................................................... 12
2.4.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies ..... 12
2.4.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility ............................................................................................................................ 12
2.4.5 Select RACT ........................................................................................................................ 12
2.5 Boilers ................................................................................................................................................. 13
2.5.1 Reasonably Available Control Technologies ..................................................................... 13
2.5.2 Eliminate Technically Infeasible Control Technologies .................................................... 13
2.5.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies ..... 13
Table of Contents

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1_RACT Analysis
2.5.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility ............................................................................................................................ 13
2.5.5 Select RACT ........................................................................................................................ 14
Section 3: Conclusion ............................................................................................................................... 15
Attachment A: 2021 BACT - Cogen Engines ............................................................................................... A
Attachment B: 2023 BACT - Emergency Engines .........................................................................................
Attachment C: Flare Replacement Cost Estimate ........................................................................................
Attachment D: Boiler Retrofit Emissions Reduction ....................................................................................
Attachment E: Cost Escalation ......................................................................................................................

List of Tables
Table 1. Emission Sources .......................................................................................................................... 5
Table 2. Revised Estimated Costs for Engine Controls ............................................................................. 8
Table 3. Estimated Ongoing Cost of SCR Control ...................................................................................... 9
Table 4. RBLC BACT Methods of Control ................................................................................................. 11

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1_RACT Analysis
List of Abbreviations
BACT Best Available Control Technology
Btu British thermal unit
CH4 methane
CO carbon monoxide
CO2 carbon dioxide
Cogen Cogeneration
CVWRF Central Valley Water Reclamation Facility
DAQ Division of Air Quality
g/hp-hr grams per horsepower-hour
ICE internal combustion engine
LAER Lowest Achievable Emission Rate
MMBtu/hr million Btu per hour
NAA Nonattainment Area
NAAQS National Ambient Air Quality Standard
NOx nitrogen oxide
PM10 particulate matter 10 micrometers
PM2.5 particulate matter 2.5 micrometers
ppm parts per million
RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
SCAQMD South Coast Air Quality Management District
SCR selective catalytic reduction
SIP State Implementation Plan
SO2 Sulfur dioxide
USEPA United States Environmental Protection Agency
VOC volatile organic compound

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Section 1: Background
The Central Valley Water Reclamation Facility (CVWRF) is located at 800 West Central Valley Road in Salt
Lake City, Salt Lake County, Utah. CVWRF treats wastewater using a combination of processes. Every day,
between 50 and 60 million gallons of wastewater are conveyed into the facility for treatment. Those millions
of gallons of water are processed, impurities are separated and treated, and harmful bacteria, protozoa, and
viruses are eliminated so that only clean water is returned to Mill Creek and the Jordan River.
1.1 Site History and Permitting Timeline
CVWRF is currently permitted under Title V Air Permit 3500191001, issued March 16, 2020, through the
State of Utah, Department of Environmental Quality, Division of Air Quality (DAQ). Emissions at the facility are
primarily associated with electric power generation from the operation of prime-use digester gas/natural
gas-fueled engine generators and standby emergency diesel engine generators.
Due to an anticipated change in attainment status, the facility is required to perform a Reasonably Available
Control Technology (RACT) Analysis.
1.2 Attainment Status
CVWRF is located in Salt Lake County, Utah which is currently designated non-attainment for PM2.5, SO 2 and
ozone; the area is also designated as a PM10 maintenance area. Specific non-attainment status (marginal,
moderate, serious, etc.) is designated by the degree to which an area does not meet the national primary or
secondary ambient air quality standard for a National Ambient Air Quality Standard (NAAQS) pollutant. Salt
Lake County was designated as marginal non-attainment for ozone on June 4, 2018. Since the area was not
able to attain the ozone standard within the three-year period allowed by United States Environmental Pro-
tection Agency (USEPA), the area was re-designated as moderate non-attainment for ozone on November 7,
2022.
Ozone is not emitted directly into the air, but is formed through the photochemical reaction of nitrogen ox-
ides (NOx) and volatile organic compounds (VOCs). NOx and VOCs are known as ozone precursor gases,
which are, for the most part, emitted directly into the atmosphere.
The Northern Wasatch Front Ozone Nonattainment Area (NAA) is required to attain the ozone standard by
August 3, 2024; however recent monitoring data indicates the Northern Wasatch Front NAA will not attain
the standard and will be reclassified to serious non-attainment of ozone in February of 2025. The serious
non-attainment classification will trigger requirements for major stationary sources and new thresholds for
major stationary sources (50 tons per year or more of NOx or VOCs). The facility is estimated to have a poten-
tial to emit exceeding 50 tons per year of NOx, triggering the new major source threshold under the Northern
Wasatch Front NAA reclassification. The Ozone Implementation Rule in 83 FR 62998 requires the State Im-
plementation Plan (SIP) to include RACT for all major stationary sources in nonattainment areas classified as
moderate or higher.
1.3 Description of Emissions Units
The following emissions units are covered by the Title V permit (3500191001) last revised on September 9,
2021 and are sources of NOx.

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1_RACT Analysis
Table 1. Emission Sources
Emission Source Description
Digester Gas/Natural Gas Generator Engines (4)
Cogeneration Engines #1, #2, #3, #4
Four (4) GE Jenbacher Model JMS 612-F28F02 generator engines
Rating: 2,509 hp (each)
Fuel Type: Digester Gas/Natural Gas*
*Digester gas is the primary fuel
Emergency Generator Engines (10)
#2 and #3 – Rating: 896 hp each
#4 – Rating: 349 hp
#5 and #6 – Rating: 800 hp each
#7 and #8 – Rating 1,341 hp each
#9, #10, and #11 – Rating: 2,884 bhp/2000kW each
Fuel Type: Diesel
Waste Oil Heaters (3) Rating: 0.28, 0.33, and 0.35 MMBtu/hr each
Fuel Type: Used Oil
Digester Gas Flares (2) Fuel Type: Digester Gas
Type: Candlestick
Boilers (2)
Boiler #1 Rating: 6.05 MMBtu/hr
Boiler #2 Rating: 6.28 MMBtu/hr
Fuel Type: Natural Gas
Reasonably Available Control Technology Analysis for NOx

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1_RACT Analysis
Section 2: RACT Analysis
A RACT analysis requires implementation of the lowest emission limitation that an emission source is capa-
ble of meeting by the application of a control technology that is reasonably available, considering technologi-
cal and economic feasibility. A RACT analysis must include the latest information when evaluating control
technologies. Control technologies evaluated for a RACT analysis can range from work practices to add-on
controls. As part of the RACT analysis, current control technologies already in use for NOx sources can be
taken into consideration. To conduct a RACT analysis, a top-down analysis is used to rank all control technol-
ogies:
 Step 1: Identify all reasonably available control technologies
 Step 2: Eliminate technically infeasible control technologies
 Step 3: Rank remaining control technologies based on capture and control efficiencies
 Step 4: Evaluate remaining control technologies on economic, energy, and environmental feasibility
 Step 5: Select RACT
The following presents the detailed RACT analysis for the emission units identified in Section 1.3.
2.1 JMS Digester Gas/Natural Gas Cogeneration Engines
2.1.1 Reasonably Available Control Technologies
A BACT analysis was completed for the Cogeneration Engines dated February 11, 2021. This BACT analysis
is provided as Attachment A in full, and has been utilized in the RACT analysis.
Several existing sources of information were used to identify emission controls that had been used for simi-
lar projects. The Utah DEQ, Air Quality Division did not have a RACT determination for a comparable digester
gas engine. BC conducted a search of the following BACT databases:
 USEPA RACT/BACT/LAER Clearinghouse (RBLC) - Category 17.140 – Internal Combustion Engines (ICE)
– Large (>500 hp) – Landfill/Digester/Bio-Gas
 California Statewide BACT Clearinghouse –ICE: Landfill or Digested Gas Fired
The results of these searches are included in the BACT analysis included in Attachment A. Table B-1 of At-
tachment A contains the RACT Determinations for Engines that were found in the USEPA RACT/BACT/LAER
Clearinghouse for Category 17.140 firing on landfill/digester/bio-gas. The search yielded 20 potential pro-
jects for consideration. Table B-2 of Attachment A contains the results of a search of the California Statewide
BACT Clearinghouse. Three projects were found, although one is a repeat from the USEPA RBLC.
All of the projects from the EPA database used landfill gas as fuel. While landfill gas and digester gas, can
both be categorized as “biogas,” they are dissimilar in composition. Digester gas is generally higher in heat
content than landfill gas and is comprised primarily of methane (CH4) and carbon dioxide (CO2). Landfill gas,
on the other hand, typically contains less CH4 and includes a mixture of various organic chemicals. As a con-
sequence, combustion of digester gas and landfill gas will emit different pollutants at different levels. There-
fore, landfill gas projects are not considered comparable to the proposed project.
The California Air Resources Board Statewide search yielded two digester gas fired projects, both of which
have lower emissions limits for NOx than the cogeneration engines. The City of Santa Maria Wastewater
Treatment Plant has a much smaller engine and does not provide many details on emission control, there-
fore it was excluded from the BACT analysis.
Reasonably Available Control Technology Analysis for NOx

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1_RACT Analysis
The project most similar in design, by engine size, is Orange County Sanitation District which uses an oxida-
tion catalyst and selective catalytic reduction (SCR) for emission controls. This document will go into further
detail about the infeasibility of installing SCR controls for the cogeneration engines. Orange County Sanita-
tion District is located in the South Coast Air Quality Management District (SCAQMD) noted for its extremely
poor air quality (serious non-attainment for PM2.5 and extreme nonattainment for ozone), with three times
the population of Salt Lake County. The emission controls required in SCAQMD are much stricter than in any
other part of the United States, making that project not comparable.
In addition to the 2021 BACT analysis, an updated search of the EPA database using the same Category
17.140 was conducted on September 26, 2023. No new digester gas fired sources nor new control technol-
ogies were identified in that search.
2.1.2 Eliminate Technically Infeasible Control Technologies
The control technologies identified above (oxidation catalyst and SCR) are considered technologically feasi-
ble for the cogeneration engines.
2.1.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies
An add-on SCR control device is expected to provide 90% control of NOx emissions. An oxidation catalyst will
not provide control of NOx emissions.
2.1.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility
During a BACT analysis dated February 11, 2021, Mr. Jim Schettler, PE, Brown and Caldwell’s Vice President
of Mechanical Engineering, completed a conceptual cost analysis to retrofit engines 3 and 4 with oxidation
catalyst and an SCR system. This analysis is found in Attachment A (Attachment C of the 2021 BACT report).
To add these controls would require significant redesign including:
 Additional equipment cost for the control equipment.
 Redesign and reconfiguration of all exhaust piping for both engines.
 Additional sensors, wiring and controls.
 Additional equipment installation costs.
 Structural modifications to the engine building, including the 2nd and 3rd deck, roof, and building wall.
 Increased engineering costs.
As detailed in Attachment C, costs to retrofit the engines to add SCR as well as oxidation catalysts would to-
tal $656,000 per engine (or $2,624,000 total) in 2021. Since the addition of oxidation catalysts would not
improve NOx emissions, the costs above have been adjusted to account for installation of the SCR systems
only, bringing the cost down to $556,800 per engine (or roughly $2,227,208 for all 4 engines) in 2021 dol-
lars. [It was assumed that 1/3 of the costs for the “Oxidation catalyst + SCR system” and 1/3 of the costs for
the “Equipment installation” were attributable to installation of the oxidation catalysts.]

Reasonably Available Control Technology Analysis for NOx

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1_RACT Analysis
Table 2. Revised Estimated Costs for Engine Controls
Equipment Item Size Cost, each $ Remarks
SCR system (1/3 reduction for omitting oxidation cat.) For each engine 93,333 vendors quotes
Urea solution atomizing air compressor For this size SCR 6,000 complete
Urea solution atomizing air piping 60' per engine 1,440 approx.
Urea solution storage tank, 600 gallons HDPE 4,500 vendors quotes
Urea solution storage tank, fill and vent piping 3" 3,450 HDPE
Urea solution fill pump as needed 7,500 gear pump
Replacing 20" SST piping with 24" SST 46' each engine 31,280 sch 10S
High temp exhaust piping insulation, 24" dia 2" thick, 50' 7,200 approx.
24" SST piping supports lump sum 3,754
Expansion joints for 24" SST pipe 3 per engine 13,500 SST bellows
Urea solution piping, 1/2" SST 65' per engine 1,560
Subtotal $ 173,517
SCR sensors & electric controls wiring and controls 13,881 8%
Electrical wiring, motor starters, conduit, and misc. 27,763 16%
Subtotal $ 215,161
Equipment installation, per "RS Means Guide" at 35% 75,306 estimating guide
Structural steel modifications to 2nd deck approx.. 65,000 retrofit
Structural steel modifications to 3rd deck approx.. 28,000 retrofit
Structural modifications to roof approx.. 23,400 retrofit
Structural mods to building wall for 24" EE dia approx.. 31,560 retrofit
Subtotal $ 438,427
Engineering costs at 12% 52,611 typical, retrofit
Contingency at 15% 65,764
Total for each engine-generator $ 556,802 Approximately

Using the current prime lending rate of 8.5% (Wall Street Journal prime rate, 10/17/2023) and an expected
life of 20 years, the following formula was utilized to provide an annualized value for the construction cost
for SCR on the engines.
𝐵=𝑃𝑉∙ቄ ௜
ଵି(ଵା௜)ష೙ቅ (Eq. 1)
Where:
B = annualized control cost
PV = present day value of the control technology
i = interest rate at which the source can borrow money (8.5%)
n = life of equipment (number of years)
Using Equation 1 results in a $235,351.24 annualized value for the construction cost to install SCR on all
four engines.
In addition to construction costs, SCR will require ongoing costs as detailed in Table 3 below.

Reasonably Available Control Technology Analysis for NOx

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1_RACT Analysis
Table 3. Estimated Ongoing Cost of SCR Control

IC Engine SCR System Ongoing Costs of Operation
SCR System Costs for an 1812 kW INNIO Jenbacher JMS 616 Spark Gas IC Engine Generator
Jim Schettler, BC
SCR System Electrical Operating Cost 10/20/2023
Atomizing air compressor 5 HP load approximate
4.14 kWe load
electricity cost $2,957 per year
Urea solution booster pump 0.5 HP load approximate
0.44 kWe load smaller motors are less efficient
electricity cost $313 per year
SCR system instruments, controls, heaters 600 watts approximate, 6 instruments
0.60 kWe load
electricity cost $428 per year
Urea heating 200 watts during cold weather hours
0.20 kWe load
electricity cost $34 per year for 2,000 hr/yr operation
Freeze protection 200 watts during cold weather hours
0.20 kWe load
electricity cost $34 per year for hr/yr operation
Urea Instruments 200 watts approximate, 6 instruments
0.20 kWe load
electricity cost $143 per year
SCR System Electrical Operating Cost, total $3,910 per year approximate
Urea Cost Urea solution usage, per hour 5.2 gals per hour, per similar engine-generator
SCR system urea dosing 8,300 hours per year, per engine-generator
Urea solution yearly usage 42,835 gallons per year, per continuously operated engine-generator
Urea solution unit cost $2.40 per gallon, at 42.5 % urea solution
Urea solution annual cost $102,805 per year, each operating engine-generator
Engine Lubrication, Added Cost of Low Ash Lube Oil (required for SCR catalyst)
Added cost per gallon of low ash lube oil $5 estimate
Jenbacher JMS616 engine lube capacity 180 gallons
Engine oil changes per year 5 approximately every 1600 operating hours
Added low ash engine lube oil cost $4,500 per year, each operating engine-generator
SCR Catalyst Media Core Replacement
SCR catalyst core replacement frequency every 6 years approximate, per Bob Erdman, sales engineer
SCR catalyst core replacement cost, complete $32,000 per catalyst supplier for San Diego project
SCR catalyst core replacement cost, per year $5,333 per year annualized
SCR System Testing Cost
engine exhaust source test costs $3,750 per year by an independent testing firm (estimate per Best Environmental)
Total yearly operating cost $120,000 for each engine-generator
Assumptions:$0.008 calculated cost per kWhr, average
0.086$ per kWh - electricity cost
8,300 hr/yr engine operating time
2,000 hr/yr cold weather operating hours
Reasonably Available Control Technology Analysis for NOx

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1_RACT Analysis
Equation 2 was then utilized to provide the annualized cost of control.
𝐴=𝐵+𝐶
𝐷 (Eq. 2)
Where:
A = annualized cost of control ($/ton of pollutant removed)
B = annualized control cost (construction cost, per Equation 1 above)
C = annual ongoing cost of control ($/year)
D = Reduction in emissions (tons/year)

Assuming the SCR systems will reduce NOx emissions by 90% yields a reduction of 31.12 tons of NOx. The
cost-effectiveness of the SCR systems then equates to $22,985 per ton of NOx removed. Table 2-13 (Cost
and Cost Effectiveness Summary for NOx Control Techniques Applied to Lean-Burn SI Engines) in EPA’s Alter-
native Control Techniques Document (EPA-453/R-93-032) published in July 1993 provides an estimated
cost-effectiveness threshold for the 2,509 HP engines of $890/ton NOx removed (in 1991 dollars). When
these costs are escalated to current (year 2023) costs, the cost-effectiveness threshold is estimated to be
roughly $2,500/ton NOx removed (based on Engineering News Record cost data). When comparing the esti-
mated cost of control to the cost-effectiveness guidelines, the addition of SCR control is not considered cost-
effective for the engines.
This discussion does not account for direct and indirect environmental costs associated with storage and
handling of the urea necessary for the system. Therefore, for these reasons, we find additional emissions
controls to be infeasible for the cogeneration engines.
2.1.5 Select RACT
Per the analysis in Section 2.1.4, no RACT has been identified that is economically feasible for the existing
cogeneration engines.
2.2 Diesel Fired Emergency Generators
2.2.1 Reasonably Available Control Technologies
A BACT analysis was completed for the Diesel Fired Emergency Generators dated June 26, 2023. This BACT
analysis is provided as Attachment B in full, and has been utilized in the RACT analysis.
Several existing sources of information were used to identify emission controls that have been used for simi-
lar projects. The Utah DEQ, Air Quality Division did not have any NOx RACT determination for a comparable
internal combustion engine. In response to the area around the facility having been recently designated non-
attainment for ozone, the Utah DEQ website contains area source rules which apply to several specific
source categories; none of the rules apply directly or indirectly to internal combustion engines.
BC conducted an initial search of the following BACT database:
 USEPA RBLC – Category 17.110 – Internal Combustion Engines – Large (>500 hp) – Fuel Oil (kerosene,
aviation, and diesel) with a keyword search for “emergency”
The results from the RBLC initially provided over 6,000 potential determinations. However, the results were
further refined through filtering the information as follows:
 Engines fired on fuel other than diesel were removed
 Engines driving fire pumps were removed
Reasonably Available Control Technology Analysis for NOx

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1_RACT Analysis
 Smaller engines (roughly under 1,000 hp) were removed
 Pollutants were limited to NOx only
The refined RBLC results provided 18 BACT determinations. The remaining control technologies for NOx cited
are listed in Table 4 below.

Table 4. RBLC BACT Methods of Control
Pollutant Methods of Control
NOx Emission Limit: 3.95 g/HP-hr – 4.46 g/HP-hra
a. The RBLC entry did not specify the method of control. BC requested verification from the
agency which submitted the determination for the NOx emission limit (PA 0291) and
received a response from the Pennsylvania Department of Environmental Protection stating
that the source had never been constructed. Therefore, this emissions limit was not
demonstrated as achieved in practice and was not brought forward for consideration as
RACT.

As noted in the footnote for the NOx emission standard in Table 4 above, according to an email from the
Pennsylvania Department of Environmental Protection, the facility subject to the NOx emission limit was
never constructed and the limit was not achieved in practice. Therefore, this RACT determination was not
brought forward.
2.2.2 Eliminate Technically Infeasible Control Technologies
Not applicable as no control technologies are identified.
2.2.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies
Not applicable as no control technologies are identified.
2.2.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility
Not applicable as no control technologies are identified.
2.2.5 Select RACT
Per the analysis in Section 2.2.1, no RACT has been identified for the existing emergency generator engines.
2.3 Waste Oil Heaters
2.3.1 Reasonably Available Control Technologies
Existing sources of information were used to identify emission controls that have been used for similar pro-
jects. BC conducted an initial search of the following BACT database:
 USEPA RBLC – All Process Types, Process Name Contains: “waste oil”
The results from the RBLC provided zero potential determinations.
2.3.2 Eliminate Technically Infeasible Control Technologies
Not applicable as no control technologies are identified.
2.3.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies
Not applicable as no control technologies are identified.
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1_RACT Analysis
2.3.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility
Not applicable as no control technologies are identified.
2.3.5 Select RACT
Per the analysis in Section 2.3.1, no RACT has been identified for the existing waste oil heaters.
2.4 Digester Gas Flares
2.4.1 Reasonably Available Control Technologies
Existing sources of information were used to identify emission controls that have been used for similar pro-
jects.
BC conducted an initial search of the following BACT database:
 USEPA RBLC – Category 19.320– Digester and Landfill Gas Flares – Pollutant Name: NOx
The results from the RBLC initially provided 5 potential determinations. The method of control for the 5 de-
terminations considered were listed as “good combustion practices” and installation of a gas collection sys-
tem with a flare. However, two of the processes noted that control was achieved using an enclosed flare.
Since enclosed flares are commonly used for combustion of excess digester gas at wastewater treatment
plants and the facility currently uses an open flare, this RACT review considered the use of an enclosed flare
for providing NOx control.
2.4.2 Eliminate Technically Infeasible Control Technologies
Use of an enclosed flare is considered technologically feasible for combustion of excess digester gas at the
plant.
2.4.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies
Use of enclosed flares is the only control technology being considered. Based on a literature review of NOx
emission factors for open flares and enclosed flares, it is expected that use of an enclosed flare would pro-
vide approximately a 12% reduction in NOx emissions (0.06 lb NOx/mmbtu for an enclosed flare versus
0.068 lb NOx/mmbtu for an open flare). This would result in a 0.06 ton per year NOx reduction at the facility.
2.4.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility
Using Equations 1 and 2 (described in Section 2.1.4), together with a recent cost proposal received by BC for
a project in Washington State as well as data provided by BC’s subject matter experts for ongoing costs for
an enclosed flare, the cost of control is estimated to be roughly $ 568,000 per ton of NOx removed. (See At-
tachment D for information on the flare cost breakdown.)
BC did not find a cost-effectiveness threshold specific to NOx emissions from flares, but the cost-effective-
ness threshold for NOx is $ 17,500 per ton of NOx reduction in the Bay Area Air Quality Management District
(BAAQMD) in California. Using this threshold for comparison purposes finds that the cost of replacing the ex-
isting flare with an enclosed flare is not economically feasible.
2.4.5 Select RACT
Per the analysis in Section 2.4.4, no RACT has been identified that is economically feasible for the existing
digester gas flares.
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1_RACT Analysis
2.5 Boilers
2.5.1 Reasonably Available Control Technologies
Existing sources of information were used to identify emission controls that have been used for similar pro-
jects.
BC conducted an initial search of the following BACT database:
 USEPA RBLC – Category 13.310 – Commercial/Institutional-Size Boilers/Furnaces (<100 million BTH/H)
– Gaseous Fuel & Gaseous Fuel Mixtures – Natural Gas; Pollutant Name: NOx
The results from the RBLC initially provided 189 potential determinations. However, the results were further
refined to 18 entries through filtering the information as follows:
 Larger boilers (greater than 10 MMBtu/hr) were removed
 Boilers without a throughput listed (0 MMBtu/hr) were removed
 Boilers without a control method description were removed
The remaining entries identified the following as possible control technologies for NOx for natural gas-fired
boilers of similar design and size:
 Low NOx burners
 Good combustion practices
 Use of pipeline quality natural gas
Control technologies, good combustion practices, and use of pipeline quality natural gas are already imple-
mented and thus will not be considered any further in this evaluation. This document will go into further de-
tail about the infeasibility of installing the low NOx burners for the boilers.
2.5.2 Eliminate Technically Infeasible Control Technologies
All control technologies are technically feasible.
2.5.3 Rank Remaining Control Technologies Based on Capture and Control Efficiencies
The only control technology under evaluation is the use of low NOx burners. Low NOx burners capable of
achieving 30 ppm NOx in the exhaust are estimated to provide approximately 68% NOx reduction.
2.5.4 Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility
Mr. Jim Schettler, PE, Brown and Caldwell’s Vice President of Mechanical Engineering, completed a concep-
tual cost analysis to retrofit boilers 1 and 2 with low NOx burners. This analysis is found in Attachment C. To
replace the existing burners with 30 ppm NOx Weishaupt burner using flue gas recirculation as the low NOx
technique, the combined cost including burner, installation, and start-up services would cost $80,000 each
or $160,000 total. As shown in Attachment D, the cost of controls is calculated to be $45,184 per ton NOx
removed for Boiler #1 and $43,529 per ton NOx removed for Boiler #2.
Table 6-11 (NOx Control Cost Effectiveness Without/With CEM System, Natural-Gas-Fired ICI Boilers) in EPA’s
Alternative Control Techniques Document -- NOx Emissions from Industrial / Commercial / Institutional (lCI)
Boilers (EPA-453/R-94-022) provides an estimated cost-effectiveness thresholds for retrofitting an existing
10 MMBtu/hr boiler with low NOx burners. The costs provided range from $3,260 to $4,300 per ton NOx re-
moved (in 1992 dollars). When the upper end of this cost range is escalated to current (year 2023) costs,
the cost-effectiveness threshold is estimated to be roughly $11,400/ton NOx removed (based on
Reasonably Available Control Technology Analysis for NOx

14
1_RACT Analysis
Engineering News Record cost data). When we compare the estimated cost of control to the cost-effective-
ness guideline, retrofitting the boilers with low NOx burners is not considered cost-effective.
Therefore, we find retrotting the existing boilers for NOx control to be infeasible.
2.5.5 Select RACT
Per the analysis in Section 2.5.4, no RACT has been identified that is economically feasible for the existing
boilers.
Reasonably Available Control Technology Analysis for NOx

15
1_RACT Analysis
Section 3: Conclusion
In conclusion, control technologies were identified for the following equipment:
1. Cogeneration engines
2. Diesel powered emergency generators
3. Flares
4. Boilers
All control technologies identified were determined to be technically or economically infeasible.
Reasonably Available Control Technology Analysis for NOx

A
1_RACT Analysis

Attachment A: 2021 BACT - Cogen Engines

Technical Memorandum

Limitations:
This document was prepared solely for Central Valley Water Reclamation Facility in accordance with professional standards at the time the services
were performed and in accordance with the contract between Central Valley Water Reclamation Facility and Brown and Caldwell dated
December 16, 2020. This document is governed by the specific scope of work authorized by Central Valley Water Reclamation Facility; it is not
intended to be relied upon by any other party except for regulatory authorities contemplated by the scope of work. We have relied on information or
instructions provided by Central Valley Water Reclamation Facility and other parties and, unless otherwise expressly indicated, have made no
independent investigation as to the validity, completeness, or accuracy of such information.
11020 White Rock Road, Suite 200
Rancho Cordova, CA 95670

T: 916-444-0123

Prepared for: Central Valley Water Reclamation Facility
Project Title: TO 2016-01 Cogen Replacement
Project No.: 148855
Technical Memorandum
Subject: Best Available Control Technology Determination for Cogen Engines 3 and 4
Date: February 11, 2021
To: Bryan Mansell, Plant Engineer
From: Jennifer Marchek
Copy to: File

Prepared by:
Jennifer Marchek, Principal Engineer

Reviewed by:
Jason Wiser, Project Manager

Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

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Table of Contents
Section 1: Background ............................................................................................................................................. 1
1.1 Site History and Permitting Timeline .............................................................................................................. 1
1.2 Attainment Status............................................................................................................................................ 2
1.3 Description of Engines .................................................................................................................................... 2
Section 2: BACT Analysis .......................................................................................................................................... 2
2.1 Pollutants for Which BACT is Required .......................................................................................................... 3
2.2 Control Technologies and/or Emission Limits ............................................................................................... 3
Section 3: Infeasibility of Controls ........................................................................................................................... 4
Section 4: Conclusion ............................................................................................................................................... 5
Attachment A: Engine Specifications ....................................................................................................................... A
Attachment B: BACT Database Search Results ...................................................................................................... B
Attachment C: Additional Controls Retrofit Cost Estimate ..................................................................................... C

List of Tables
Table 1. CVRWF Title V Emissions Limits for Jenbacher Engines 1 and 2 ............................................................ 1
Table 2. Manufacturer's Emission Guarantees ...................................................................................................... 2
Table 3. Applicable Emission Limits from 40 CFR, Part 60, Subpart JJJ for
Landfill/Digester Gas >1,350hp ........................................................................................................... 4
Table 4. Most Stringent Emission Rates Identified for Digester Gas Fired Engines ............................................ 4

Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

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Section 1: Background
The Central Valley Water Reclamation Facility (CVWRF) is located at 800 West Central Valley Road in Salt
Lake City, Salt Lake County, Utah. CVWRF treats wastewater using a combination of processes. Every day,
between 50 and 60 million gallons of wastewater are collected and flow into the facility for treatment. Those
millions of gallons of water are processed, impurities are separated and treated, and harmful bacteria,
protozoa, and viruses are eliminated so that only clean water is returned to Mill Creek and the Jordan River.
1.1 Site History and Permitting Timeline
CVWRF has a Title V Air Permit though the State of Utah, Department of Environmental Quality, Division of Air
Quality (DAQ), Permit 3500191001, issued March 16, 2020, which expires March 16, 2025. Emissions are
primarily associated with electrical generation from the operation of digester gas engines and emergency
generators.
In 2016 CVWRF began a project to update its five older Waukesha digester gas/natural gas engines with
four 2,509 horsepower (hp) GE Jenbacher engines (engine details are provided in Attachment A). The newer
engines must be installed and commissioned one at a time to ensure continuous operation. The facility
obtained an air permit (DAQE-AN104140012-17) from DAQ for all four new Jenbacher engines in 2017 and
purchased all four engines at that time. DAQ conducted the Best Available Control Technology (BACT)
analysis and approved all four engines as meeting BACT at the time of permit approval. The project
experienced several delays in scheduling and in 2019 the DAQ modified the permit to include only engines 1
and 2, with CVWRF intending to install the new engines in 2023. In 2020 CVWRF made gains in the
schedule and is now prepared to install engines 3 and 4 in 2021. Upon submittal of an NOI to add engines 3
and 4 into the permit, DAQ asked for an updated BACT analysis for engines 3 and 4. This document is the
response to that request.
The Title V permit contains the following emission limits for the new engines as shown in Table 1.

Table 1. CVRWF Title V Emissions Limits for Jenbacher Engines 1 and 2
Pollutant Digester Gas Mode Emission Limit (g/bhp-hr) Natural Gas Mode Emission Limit (g/bhp-hr)
VOC 1 0.7
NOx 0.55 0.55
CO 2.5 2.0
CO = Carbon Monoxide
NOx = Nitrogen Oxides
VOC = volatile organic compound

Engines 1 and 2 have been source tested and meet these emission limits. The permit does not contain limits
for sulfur dioxide (SO2), Particulate Matter less than 10 Microns (PM10), or Particulate Matter less than 2.5
microns (PM2.5).
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1.2 Attainment Status
CVWRF is located in Salt Lake County, which is currently a non-attainment area for PM2.5, SO2 and Ozone,
and designated as maintenance status for PM10. At the commencement of the engine replacement project,
Salt Lake County was in attainment with the Federal 8-hour Ozone standard. In 2018, the area’s status was
changed to marginal non-attainment for Ozone.
1.3 Description of Engines
At the time of purchase of all four engines and installation of engines 1 and 2, the manufacturer emission
guarantees for the engines were as noted in Table 2 below and included as Attachment A

Table 2. Manufacturer's Emission Guarantees
Pollutant Emission Rate (g/bhp-hr)
NOx 0.55
CO 2.5
Non-methane Hydrocarbons 0.3
Non-methane Ethane Hydrocarbons 0.2
PM10 0.03
PM2.5 0.02

Section 2: BACT Analysis
Following United States Environmental Protection Agency (USEPA) Guidance, BACT can be defined as the
most stringent of the following:
• The lowest emission rate or most effective emission limitation successfully achieved in practice by the
same type of equipment, combusting the same type of fuel.
• The lowest emission rate or most effective emission control device determined to be technically feasible
and cost effective for the equipment being installed, combusting the same type of fuel.
• The requirements of a Utah or Federal Performance Standard Regulation.
A BACT analysis is performed on a case-by-case basis and must consider emission rates and/or control
technologies that have been achieved on similar equipment or that are technically feasible and cost
effective. These requirements have led to development of a standard procedure for case-by-case “top down”
BACT analyses.
• Step 1: Identify pollutants for which BACT is required. Utah Department of Environmental Quality (DEQ)
regulations require BACT for all criteria pollutants.
• Step 2: Identify emission rates and/or control technologies. Once the pollutants for which the BACT
analysis is required are identified, candidate emission rates and/or control technologies must be
identified.
• Step 3: Evaluate technical feasibility of the emission rates and/or control technologies identified in Step
2. Any emission rates and/or control technologies that are not technically feasible should be eliminated
at this step.
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• Step 4: Ranking of remaining emission rates and/or control technologies by effectiveness. This ranking
should consider, as appropriate, control efficiency, resulting emission rates, energy impacts (fuel use,
etc.), and environmental impacts (secondary air emissions, hazardous waste production, impacts to
other media, etc.).
• Step 5: Cost effectiveness evaluation of the most stringent emission rates and/or most effective
controls.
• Step 6: Select BACT.
2.1 Pollutants for Which BACT is Required
This BACT analysis considered emissions of NOx, CO, VOC, PM10, PM2.5, and SO2.
2.2 Control Technologies and/or Emission Limits
Several Sources of information were used to identify emission controls that had been used for similar
projects. The Utah DEQ, Air Quality Division did not have any BACT determination for a comparable digester
gas engine. BC conducted an initial BACT determinations search of the following databases:
• USEPA Reasonable Available Control Technology (RACT)/BACT/Lowest Achievable Emission Rate (LAER)
Clearinghouse - Category 17.140 – Internal Combustion Engines (ICE) – Large (>500 hp) –
Landfill/Digester/Bio-Gas
• California Statewide BACT Clearinghouse –ICE: Landfill or Digested Gas Fired
The results of these searches are found in Attachment B. Table B-1 contains the BACT Determinations for
Engines that were found in the USEPA RACT/BACT/LAER Clearinghouse for Category 17.140 (ICE) firing on
landfill/digester/bio-gas). The search yielded 20 potential projects for consideration. Table B-2 contains the
results of a search of the California Statewide BACT Clearinghouse. Three projects were found, although one
is a repeat from the USEPA RBLC.
All of the projects from the EPA database used landfill gas as fuel. Landfill gas and digester gas, while both
can be categorized as “biogas”, are dissimilar in composition. Digester gas is generally higher in heat
content than landfill gas and is made up of almost pure methane and carbon dioxide (CO2). Landfill gas, on
the other hand, is made up of a mixture of various organic chemicals. As a consequence, combustion of
digester gas and landfill gas will emit different pollutants at different levels. Therefore, landfill gas projects
are not considered comparable to the proposed project.
The California Air Resources Board Statewide search yielded two digester gas fired projects, both of which
have lower emissions limits for NOx, VOC, and CO than engines 3 and 4. Neither digester gas projects
contained emission limits for PM10, PM2.5 and SO2. The City of Santa Maria Wastewater Treatment Plant is
a much smaller engine and does not provide many details on emission control, therefore it was excluded.
The project most similar in design, by engine size, is Orange County Sanitation District which uses an
oxidation catalyst and selective catalytic reduction (SCR) for emission controls. This document will go into
further detail about the infeasibility of installing this level of controls for engines 3 and 4. Orange County
Sanitation District is located in the South Coast Air Quality Management District (SCAQMD) noted for its
extremely severe air pollution (serious non-attainment for PM2.5 and extreme nonattainment for Ozone),
with three times the population of Salt Lake County. The emission controls required in SCAQMD are much
stricter than in any other part of the United States, making that project not comparable.
Additionally, BACT must consider applicable regulatory performance standards. For the engines, 40 Code of
Federal Regulations (CFR), Part 60, Subpart JJJJ is applicable. The following ICE emission limitations are
imposed by these regulations as shown in Table 3.

Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

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Table 3. Applicable Emission Limits from 40 CFR, Part 60, Subpart JJJ for
Landfill/Digester Gas >1,350hp
Pollutant Emission Limit (g/hp/hr)
NOx 2
VOC 1
CO 5
g/hp/hr = grams per horsepower per hour

Based on the investigation described herein, it was determined that one comparable project had stricter
requirements identified for NOx, CO, and VOC, while the BACT search did not specify stricter emission limits
for PM10, or PM2.5. For PM10, and PM2.5 the manufacturer’s guarantee or Title V limit will be considered
most stringent as identified in Table 4.

Table 4. Most Stringent Emission Rates Identified for Digester Gas Fired Engines
Pollutant Emission Limit (g/hp/hr) Source
NOx 0.15 Orange County Sanitation District a
CO 2.03 Orange County Sanitation District a
VOC 0.14 Orange County Sanitation District a
PM10 0.03 Manufacturer's Specifications
PM2.5 0.02 Manufacturer's Specifications
a. Project contains additional emission controls which are infeasible for this project

Section 3: Infeasibility of Controls
Mr. Jim Schettler, PE, Brown and Caldwell’s Vice President of Mechanical Engineering, completed a
conceptual cost analysis to retrofit engines 3 and 4 with oxidation catalyst and a SCR system. This analysis
is found in Attachment C. To add these controls would require significant redesign including:
• Additional equipment cost for the control equipment.
• Redesign and reconfiguration of all exhaust piping for both engines.
• Additional sensors, wiring and controls.
• Additional equipment installation costs.
• Structural modifications to the engine building, including the 2nd and 3rd deck, roof, and building wall.
• Increased engineering costs.
As detailed in Attachment C, these combined costs would total $656,000 per engine or $1,312,000 total. In
addition, this would add a significant time delay for the project; meanwhile the existing Waukesha engine 5,
which pollutes at a much higher level than the new engines 3 and 4, would continue to operate. As the
existing engine is operating outside of its useful life and prone to mechanical malfunctions, it could also lead
to shutdowns at the facility which would result in more frequent operation of the diesel standby engines and
reduce the reliability of the wastewater treatment systems. Therefore, for these reasons, we find additional
emissions controls to be infeasible for engines 3 and 4.
Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

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Section 4: Conclusion
In conclusion, CVWRF purchased and initially permitted Jenbacher engines 1, 2, 3 and 4, which at the time
were all deemed to meet BACT. Engines 1 and 2 were installed and are operational, but due to a series of
construction delays the facility was unable to meet the original schedule for installation of engines 3 and 4.
One digester gas fired ICE project found in the BACT database search utilized oxidation catalyst and SCR to
meet lower NOx and CO limits. However, at this point to install these controls for engines 3 and 4 would
require extensive redesign and significantly increased construction costs as outlined in Section 3 above. For
these reasons, we are requesting that engines 3 and 4 be considered to meet BACT without modification, as
was previously determined, and be permitted for installation by DAQ.

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Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

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Attachment A: Engine Specifications

Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

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GE Distributed Power
GE Gas Engines
Emissions Letter 8/16/2016 Page 1 of 3

16 August 2016
GE Distributed Power – GE Gas Engines confirms that the pollutants, in the amounts listed below, are confirmed as
valid "NOT TO EXCEED" values, for stationary applications per engine, and based on site gas conditions that meet
TI 1000-0300 standards for the:
Brown and Caldwell: J612 F28/F02
Pollutant Emission Limit
 NOx 0.55 g/bhp-hr (NO2)
Evaluated using EPA method 7E

 CO 2.5 g/bhp-hr
Evaluated using EPA method 10

 NMHC 0.3 g/bhp-hr
Evaluated using EPA method 18 (non-aldehydes, non-methane hydrocarbons, all CxHy with x>1)

 NMNEHC 0.2 g/bhp-hr
Evaluated using EPA method 18 (non-aldehydes, non-methane ethane hydrocarbons, all CxHy with x>2)

 PM 10 0.03 g/bhp-hr

 PM 2.5 0.02 g/bhp-hr

The following criteria apply for demonstration purposes:
(1) Operations will be on Sewage Gas, Natural Gas or a Blend all of which must meet the GE Gas Engines gas
quality requirements stated in the Technical Instruction 1000 -0300.

(2) A minimum content of 60% CH4 (air free) is required to ensure a stable combustion in our engines when
run on Sewage Gas.

(3) A minimum content of 80% CH4 (air free) is required to ensure a stable combustion in our engines when
run on Natural Gas

(4) Based on nominal mass flow as provided by the project specific data sheets or mass flow calculations
according EPA method 19.

(5) Formaldehyde – GE Gas Engines has done a significant amount of research studying formaldehyde (CH 2O)
concentrations in our engine exhaust streams. The results of this research find that formaldehyde is in
itself a difficult quantity to measure accurately and consiste ntly, however, what can be stated from our
studies is that typically, the range of formaldehyde in raw exhaust can go from 50 to 150 mg/Nm3 at 5%
O2 (0.14 TO 0.45 g/bhp-hr).

GE Distributed Power
GE Gas Engines
Emissions Letter 8/16/2016 Page 2 of 3
If a unit is running on Biogas or Landfill Gas (LFG), formaldehyde (CH 2O) is then even more difficult to
maintain and measure since Biogas/LFG are high in moisture and sulfur concentrations, which make the
use of catalysts very difficult due to the potential of catalyst poisoning.

GE Gas Engines can only guarantee formaldehyde values with an Oxidation Catalyst when we run a GE Gas
Engines Standard Natural Gas. In this case, we could achieve levels of 60~70 mg/Nm3 @ 5% O2 (0.18 to
0.22 g/bhp-hr) on the measurement method VDI 3862.

(6) For emissions shown in units of g/bhp-hr, values are valid between 80% and 100% rated stable load (not
for island mode).

(7) For emissions shown in units of mg/Nm3, values are valid between 50% and 100% rated stable load (not
for island mode).

(8) Please note that the CO and NMHC levels are for start-up only and are expected to drift slowly upwards as
deposits build up in the engine and as the engine experiences normal wear. CO drift can be decreased by
following GE Gas Engines specific maintenance and repair schedules along with the use of genuine GE Gas
Engines parts and components.

(9) Please note that the NOx level is expected to drift slowly upwards as deposits caused by contaminations in
the gas build up in the engine and as the engine experiences normal wear. NOx drift can be compensated
up to a certain extent, by calibrations to engine operating parameters in the Diane XT controls system.
Excessive deposits resulting from gas contamination may require the cleaning of the combustion chamber
and turbochargers depending on gas quality and the severity of gas contaminations.
(10) Maintenance and component repairs for the GE Gas Engines equipment is carried out by qualified
personnel strictly according to the schedules and repair requirements set by GE Gas Engines along with the
use of genuine GE Gas Engines parts and components.

(11) Testing to determine compliance with this commitment will be at the expense of the customer and
accomplished by a certified laboratory chosen by the customer. The engine/installation is to be in good
working order consistent with GE Gas Engines recommende d maintenance practices prior to any testing.
GE Gas Engines reserves the right to participate and/or challenge the results of any testing.
If the engine fails to meet the emissions representations the customer must provide the following supporting
documentation to GE Gas Engines:
(1) Fuel gas samples
(2) Complete maintenance records
(3) A full report including the calculations and results of any emissions testing.
GE Gas Engines will be given a reasonable amount of time to take any or all of the followin g actions:
 Perform additional testing in an effort demonstrate the emissions representations. If this testing
demonstrates compliance with no adjustments required to the engine, customer will pay for added testing. If
testing fails to demonstrate compliance with the emissions representations, the testing will be paid for by GE
Gas Engines.
 Make such adjustments to the engine so as to bring the engine into compliance with the emissions limits
provided in this letter.

GE Distributed Power
GE Gas Engines
Emissions Letter 8/16/2016 Page 3 of 3
Conformity Declaration (acc. ISO/IEC 17050-1:2004)
We hereby confirm that stationary GE Gas Engines comply with 40 CFR Part 60, subpart JJJJ and be labelled as
follows:

“THIS ENGINE IS EXCLUDED FROM THE REQUIREMENT OF 40 CFR PART 1048 AS A “STATIONARY ENGINE”.
INSTALLING OR USING THIS ENGINE IN ANY OTHER APPLICATION MAY BE A VIOLATION OF FEDERAL LAW
SUBJECTED TO CIVIL PENALTY AND THE OWNER/OPERATOR MUST COMPLY WITH THE REQUIREMENT OF CFR PART
60. THIS ENGINE IS NOT PART OF A REQUI RED OR VOLUNTARY CERTIFICATION PROGRAM AND IS CLASSIFIED AS
NON-CERTIFIED PER 40 CFR PART 60, SUBPART JJJJ”.

GE Distributed Power
GE Gas Engines
11330 Clay Road
Houston, TX 77041
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Technical Description
Cogeneration Unit
JMS 612 GS-B.L
with Island Operation

Brown & Caldwell
JMS 612 F28/F02, 4160V Dual Fuel
The ratings in the specification are valid for full load operation at a site installation of 4240 ft (1292 m) and an air intake
temperature of T1 < 95 F (35C). At T1 > 95 F (35C), an output deration of 1.11%/F (2.0%/C) will occur.

Electrical output 1812 kWe

Thermal output ( Biogas / Natural Gas ) 2594 / 2752 Mbtu/hr

Emission values
NOx < 0.5 g/bhp.hr (NO2)

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0.01a Technical Data on Sewage Gas (F28) (at module) ______________________ 5
0.01b Technical Data on Natural Gas (F02) (at module) ______________________ 6
Main dimensions and weights (at module)(with gearbox) 7
Connections 7
Output / fuel consumption 7
0.02 Technical data of engine ___________________________________________ 8
Thermal energy balance 8
Exhaust gas data 8
Combustion air data 8
Sound pressure level 9
Sound power level 9
0.02.01 Technical data of gearbox _______________________________________ 9
0.03 Technical data of generator ________________________________________ 10
Reactance and time constants (saturated) 10
0.04 Technical data of heat recovery ____________________________________ 11
General data - Hot water circuit 11
General data - Cooling water circuit 11
100% Biogas Thermal Connection Variant K ______________________________ 12
100% Natural Gas Thermal Connection Variant K __________________________ 13
0.10 Technical parameters_____________________________________________ 14
1.00 Scope of supply - Module _________________________________________ 16
1.01 Spark ignited gas engine __________________________________________ 16
1.01.01 Engine design (Air Start) _______________________________________ 17
1.01.02 Additional equipment for the engine (spares for commissioning) ______ 18
1.01.03 Engine accessories ____________________________________________ 19
1.01.04 Standard tools (per installation)__________________________________ 19
1.02 Generator-medium voltage ________________________________________ 20
1.03 Module Accessories ______________________________________________ 23
1.03.01 Engine jacket water system _____________________________________ 25
1.03.02 Automatic lube oil replenishing system incl. extension tank __________ 25
1.04 Heat recovery ___________________________________________________ 26
1.05a Gas train (Biogas) ______________________________________________ 26
1.05b Gas train (Natural Gas) __________________________________________ 27
1.05c Pre-chamber Gas train (Natural Gas) _______________________________ 27

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1.07 Painting ________________________________________________________ 28
1.11 Engine generator control panel per module- Dia.ne XT4 incl. Single
synchronization of the generator breaker ________________________________ 29
Touch Display Screen: 30
Central engine and module control: 32
Malfunction Notice list: 34
1.11.01 Remote messaging over MODBUS-TCP ___________________________ 36
1.11.06 Remote Data-Transfer with DIA.NE XT4 ___________________________ 37
1.11.14 Generator Overload / Short Circuit Protection ______________________ 41
1.11.15 Generator Differential Protection _________________________________ 41
1.11.16 Generator Earth Fault Protection (nondirectional) ___________________ 41
1.11.31 Interfaces to customer Master synchronization (Synchronization of grid CB)
42
1.20.03 Start System (Air Start) _________________________________________ 42
1.20.04 Battery System _______________________________________________ 43
1.20.05 Electric jacket water preheating __________________________________ 43
1.20.08 Flexible connections ___________________________________________ 44
1.20.45 Fuel Blending _________________________________________________ 44
2.00 Electrical equipment _____________________________________________ 45
2.02 Grid monitoring device ___________________________________________ 45
2.12 Gas warning device ______________________________________________ 47
2.13 Smoke warning device ____________________________________________ 47
3.70 Control Strategy and Options ______________________________________ 48
3.71 Vibration Sensor _________________________________________________ 50
3.72 Seismic Protection _______________________________________________ 50
4.00 Delivery, installation and commissioning ____________________________ 51
4.01 Carriage 51
4.02 Unloading 51
4.03 Assembly and installation 51
4.04 Storage 51
4.05 Start-up and commissioning 51
4.06 Trial run 51
4.07 Emission measurement (exhaust gas analyser) 51
5.01 Limits of delivery ________________________________________________ 52
5.02 Factory tests and inspections ______________________________________ 53

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5.02.01 Engine tests 53
5.02.02 Generator tests 53
5.02.03 Module tests 53
5.03 Documentation __________________________________________________ 54

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0.01a Technical Data on Sewage Gas (F28) (at module)

Data at: Full
load
Part Load
Fuel gas LHV BTU/scft 548
100% 75% 50%

Energy input MBTU/hr [2] 14,670 11,336 8,002
Gas volume scfhr *) 26,770 20,686 14,602
Mechanical output bhp [1] 2,509 1,881 1,255
Electrical output kW el. [4] 1,812 1,355 896
Recoverable thermal output
~ Intercooler 1st stage MBTU/hr 1,618 914 366
~ Lube oil MBTU/hr ~ ~ ~
~ Jacket water MBTU/hr 976 864 740
~ Exhaust gas cooled to 727 °F MBTU/hr ~ ~ ~
Total recoverable thermal output MBTU/hr [5] 2,594 1,778 1,106

Heat to be dissipated
~ Intercooler 2nd stage (with gearbox) MBTU/hr [9] 503 338 214
~ Lube oil MBTU/hr 752 674 578
~ Surface heat ca. MBTU/hr [7] 506 ~ ~

Spec. fuel consumption of engine electric BTU/kWel.hr [2] 8,098 8,367 8,929
Spec. fuel consumption of engine BTU/bhp.hr [2] 5,847 6,025 6,375
Lube oil consumption ca. gal/hr [3] 0.12 ~ ~
Electrical efficiency % 42.1% 40.8% 38.2%
Thermal efficiency % 17.7% 15.7% 13.8%
Total efficiency % [6] 59.8% 56.5% 52.0%

Hot water circuit:
Forward temperature °F 186.0 181.0 176.8
Return temperature °F 170.0 170.0 170.0
Hot water flow rate GPM 324.2 324.2 324.2
*) approximate value for pipework dimensioning
[_] Explanations: see 0.10 - Technical parameters

All heat data is based on standard conditions according to attachment 0.10. Deviations from the standard conditions can result in a
change of values within the heat balance, and must be taken into consideration in the layout of the cooling circuit/equipment
(intercooler; emergency cooling; ...). In the specifications in addition to the general tolerance of ±8 % on the thermal output a further
reserve of +5 % is recommended for the dimensioning of the cooling requirements.

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0.01b Technical Data on Natural Gas (F02) (at module)

Data at: Full
load
Part Load
Fuel gas LHV BTU/scft 917
100% 75% 50%

Energy input MBTU/hr [2] 14,245 10,947 7,651
Gas volume scfhr *) 15,534 11,938 8,344
Mechanical output bhp [1] 2,509 1,881 1,255
Electrical output kW el. [4] 1,812 1,355 896
Recoverable thermal output
~ Intercooler 1st stage MBTU/hr 1,437 808 279
~ Lube oil MBTU/hr ~ ~ ~
~ Jacket water MBTU/hr 1,135 1,009 839
~ Exhaust gas cooled to 677 °F MBTU/hr ~ ~ ~
Total recoverable thermal output MBTU/hr [5] 2,572 1,817 1,118

Heat to be dissipated
~ Intercooler 2nd stage (with gearbox) MBTU/hr [9] 608 373 218
~ Lube oil MBTU/hr 582 518 446
~ Surface heat ca. MBTU/hr [7] 577 ~ ~

Spec. fuel consumption of engine electric BTU/kWel.hr [2] 7,863 8,080 8,538
Spec. fuel consumption of engine BTU/bhp.hr [2] 5,677 5,818 6,095
Lube oil consumption ca. gal/hr [3] 0.12 ~ ~
Electrical efficiency % 43.4% 42.2% 40.0%
Thermal efficiency % 18.1% 16.6% 14.6%
Total efficiency % [6] 61.5% 58.8% 54.6%

Hot water circuit:
Forward temperature °F 185.9 181.2 176.9
Return temperature °F 170.0 170.0 170.0
Hot water flow rate GPM 324.2 324.2 324.2

*) approximate value for pipework dimensioning
[_] Explanations: see 0.10 - Technical parameters

All heat data is based on standard conditions according to attachment 0.10. Deviations from the standard conditions can result in a
change of values within the heat balance, and must be taken into consideration in the layout of the cooling circuit/equipment
(intercooler; emergency cooling; ...). In the specifications in addition to the general tolerance of ±8 % on the thermal output a further
reserve of +5 % is recommended for the dimensioning of the cooling requirements.

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Main dimensions and weights (at module)(with gearbox)
Length in ~ 360
Width in ~ 90
Height in ~ 110
Weight empty lbs ~ 51,460
Weight filled lbs ~ 53,660

Connections
Hot water inlet and outlet in/lbs 4''/145
Exhaust gas outlet in/lbs 20''/145
Fuel Gas (at module) in/lbs 4''/145
Water drain ISO 228 G ½''
Condensate drain in/lbs 2''/145
Safety valve - jacket water ISO 228 in/lbs 2x1½''/2.5
Safety valve - hot water in/lbs 2½''/232
Lube oil replenishing (pipe) in 1.1
Lube oil drain (pipe) in 1.1
Jacket water - filling (flex pipe) in 0.5
Intercooler water-Inlet/Outlet 1st stage in/lbs 4''/145
Intercooler water-Inlet/Outlet 2nd stage in/lbs 2½''/145

Output / fuel consumption
ISO standard fuel stop power ICFN bhp 2,509
Mean effe. press. at stand. power and nom. speed psi 290
Fuel gas type Sewage gas | Natural gas
Based on methane number | Min. methane number MN d) 135 | 100 | 94 | 80
Compression ratio Epsilon 12.5
Min. fuel gas pressure for the pre chamber psi 53.6639638
Min./Max. fuel gas pressure at inlet to gas train psi 1.74 - 2.9 c)
Allowed Fluctuation of fuel gas pressure % ± 10
Max. rate of gas pressure fluctuation psi/sec 0.145
Maximum Intercooler 2nd stage inlet water temperature °F 122
Spec. fuel consumption of engine BTU/bhp.hr 5,847 | 5,677
Specific lube oil consumption g/bhp.hr 0.15
Max. Oil temperature °F 176
Jacket-water temperature max. °F 203
Filling capacity lube oil (refill) gal ~ 145
c) Lower gas pressures upon inquiry
d) based on methane number calculation software AVL 3.2

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0.02 Technical data of engine

Manufacturer GE Jenbacher
Engine type J 612 GS-F28
Working principle 4-Stroke
Configuration V 60°
No. of cylinders 12
Bore in 7.48
Stroke in 8.66
Piston displacement cu.in 4,568
Nominal speed rpm 1,500
Mean piston speed in/s 433
Length in 167
Width in 74
Height in 99
Weight dry lbs 20,944
Weight filled lbs 22,708
Moment of inertia lbs-ft² 1345.01
Direction of rotation (from flywheel view) left
Radio interference level to VDE 0875 N
Starter motor output kW 13
Starter motor voltage V 24
Thermal energy balance
Energy input MBTU/hr 14,670 | 14,245
Intercooler MBTU/hr 2,121 | 2,045
Lube oil MBTU/hr 752 | 582
Jacket water MBTU/hr 976 | 1,135
Exhaust gas cooled to 356 °F MBTU/hr 2,393 | 2.019
Exhaust gas cooled to 212 °F MBTU/hr 3,290 | 2,900
Surface heat MBTU/hr 278 | 349
Exhaust gas data
Exhaust gas temperature at full load °F [8] 727 | 677
Exhaust gas mass flow rate, wet lbs/hr 24,368 | 23,888
Exhaust gas mass flow rate, dry lbs/hr 22,864 | 22,440
Exhaust gas volume, wet scfhr 304,560 | 302,520
Exhaust gas volume, dry scfhr 274,560 | 273,660
Max.admissible exhaust back pressure after engine psi 0.725
Combustion air data
Combustion air mass flow rate lbs/hr 22,709 | 23,243
Combustion air volume SCFM 4,692 | 4,802
Max. admissible pressure drop at air-intake filter psi 0.145

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Sound pressure level
Aggregate a) dB(A) re 20µPa 100
31,5 Hz dB 90
63 Hz dB 88
125 Hz dB 100
250 Hz dB 95
500 Hz dB 94
1000 Hz dB 93
2000 Hz dB 91
4000 Hz dB 91
8000 Hz dB 94
Exhaust gas b) dB(A) re 20µPa 116
31,5 Hz dB 104
63 Hz dB 121
125 Hz dB 124
250 Hz dB 116
500 Hz dB 111
1000 Hz dB 110
2000 Hz dB 108
4000 Hz dB 104
8000 Hz dB 86
Sound power level
Aggregate dB(A) re 1pW 122
Measurement surface ft² 1,528
Exhaust gas dB(A) re 1pW 124
Measurement surface ft² 67.60
a) average sound pressure level on measurement surface in a distance of 3.28ft (converted to free field) according to DIN 45635,
precision class 3.

b) average sound pressure level on measurement surface in a distance of 3.28ft according to DIN 45635, precision class 2.
The spectra are valid for aggregates up to bmep=319.083028 psi. (for higher bmep add safety margin of 1dB to all values per
increase of 15 PSI pressure).

Engine tolerance ± 3 dB

0.02.01 Technical data of gearbox
Manufacturer EISENBEISS
Type ~
Gearbox ratio 1:1.2
Efficiency % 99.46
Mass lbs 2,822

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0.03 Technical data of generator
Manufacturer STAMFORD e)
Type MVSI 804 R e)
Type rating kVA 2,441
Driving power bhp 2,496
Ratings at p.f.= 1.0 kW 1,812
Ratings at p.f. = 0.8 kW 1,794
Rated output at p.f. = 0.8 kVA 2,243
Rated reactive power at p.f. = 0.8 kVAr 1,346
Rated current at p.f. = 0.8 A 311
Frequency Hz 60
Voltage kV 4.16
Speed rpm 1,800
Permissible overspeed rpm 2,250
Power factor (lagging - leading) 0,8 - 1,0
Efficiency at p.f.= 1.0 % 97.3%
Efficiency at p.f. = 0.8 % 96.4%
Moment of inertia lbs-ft² 1774.12
Mass lbs 11,228
Radio interference level to EN 55011 Class A (EN 61000-6-4) N
Ik'' Initial symmetrical short-circuit current kA 2.57
Is Peak current kA 6.53
Insulation class H
Temperature rise (at driving power) F
Maximum ambient temperature °F 104

Reactance and time constants (saturated)
xd direct axis synchronous reactance p.u. 1.67
xd' direct axis transient reactance p.u. 0.16
xd'' direct axis sub transient reactance p.u. 0.12
x2 negative sequence reactance p.u. 0.17
Td'' sub transient reactance time constant ms 15
Ta Time constant direct-current ms 91
Tdo' open circuit field time constant s 4.00
e) GE Jenbacher reserves the right to change the generator supplier and the generator type. The contractual data of the
generator may thereby change slightly. The contractual produced electrical power will not change.

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0.04 Technical data of heat recovery
General data - Hot water circuit
Total recoverable thermal output MBTU/hr 2,594 | 2,572
Return temperature °F 170.0
Forward temperature °F 186.0 | 185.9
Hot water flow rate GPM 324.2
Design pressure of hot water lbs 145
min. operating pressure psi 51.0
max. operating pressure psi 131.0
Pressure drop hot water circuit psi 15.23
Maximum Variation in return temperature °F +0/-21
Max. rate of return temperature fluctuation °F/min 18

General data - Cooling water circuit
Heat to be dissipated MBTU/hr 1,255 | 1,190
Return temperature °F 122
Cooling water flow rate GPM 110
Design pressure of cooling water lbs 145
min. operating pressure psi 7.0
max. operating pressure psi 73.0
Loss of nominal pressure of cooling water psi ~
Maximum Variation in return temperature °F +0/-21
Max. rate of return temperature fluctuation °F/min 18

The final pressure drop will be given after final order clarification and must be taken from the P&ID order documentation.

100% Biogas Thermal Connection Variant K

100% Natural Gas Thermal Connection Variant K

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0.10 Technical parameters

The following “Technical Instruction (TI) of GE JENBACHER” form an integral part of the contract and must
be strictly observed:

TI 1100-0110 – Boundary Conditions for GE Jenbacher Gas Engines
TI 1100-0111 – General Conditions – Operation and Maintenance
TI 1100-0112 – Installation of GE Jenbacher Units

These Technical Instructions reference other guides and instructions which can be provided upon request.
These should be reviewed carefully by all personnel involve d with the application, installation, and
maintenance of any GE Jenbacher gas engine.

All data in the technical specification are based on engine full load (unless stated otherwise) at specified
temperatures as well as the methane number and subject to technical development and modifications. For
isolated operation an output reduction may apply according to the block load diagram. Before being able to
provide exact output numbers, a detailed site load profile needs to be provided (motor starting curves, etc.).

All pressure indications are to be measured and read with pressure gauges (psig).

(1) At nominal speed and standard reference conditions ICFN according to DIN-ISO 3046 and DIN 6271,
respectively
(2) According to DIN-ISO 3046 and DIN 6271, respectively, with a tolerance of + 5 %.
Efficiency performance is based on a new unit (immediately upon commissioning).Effects of degradation
during normal operation can be mitigated through regular service and maintenance work.
(3) Average value between oil change intervals according to maintenance schedule, without oil change
amount
(4) At p. f. = 1.0 according to VDE 0530 REM / IEC 34.1 with relative tolerances
(5) Total output with a tolerance of +/- 8 %
(6) According to above parameters (1) through (5)
(7) Only valid for engine and generator; module and peripheral equipment not considered (at p. f. = 0.8)
(8) Exhaust temperature with a tolerance of +/- 8 %
(9) Intercooler heat on:
* standard conditions (Vxx) - If the turbocharger design is done for air intake temperature > 86°F w/o de-
rating, the intercooler heat of the 1st stage need to be increased by 2%/K starting from 77°F. Deviations
between 77 – 86°F will be covered with the standard tolerance.
* Hot Country application (Vxxx) - If the turbocharger design is done for air intake temperature > 104°F
w/o de-rating, the intercooler heat of the 1st stage need to be inc reased by 2%/K starting from 95°F.
Deviations between 95 – 104°F will be covered with the standard tolerance.

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Definition of output
 ISO-ICFN continuous rated power:
Net break power that the engine manufacturer declares an engine is capable of delivering continuously, at
stated speed, between the normal maintenance intervals and overhauls as required by the manufacturer.
Power determined under the operating conditions of the manufacturer’s test bench and adjusted to the
standard reference conditions.

 Standard reference conditions:
Barometric pressure: 14.5 psi (1000 mbar) or 328 ft (100 m) above sea level
Air temperature: 77°F (25°C) or 298 K
Relative humidity: 30 %

 Volume values at standard conditions (fuel gas, combustion air, exhaust gas)
Pressure: 1 atmosphere (1013.25 mbar)
Temperature: 32°F (0°C)

Output adjustment for turbo charged engines
The ratings in the specification are valid for full load operation at a site installation of 4240 ft (1292 m) and an
air intake temperature of T1 < 95 F (35 C). At T1 > 95 F (35 C), an output deration of 1.11%/F (2.0%/C) will
occur.

Radio interference level
The ignition system of the gas engines complies the radio interference levels of CISPR 12 and EN 55011
class B, (30-75 MHz, 75-400 MHz, 400-1000 MHz) and (30-230 MHz, 230-1000 MHz), respectively.

Parameters for the operation of GE Jenbacher gas engines

Maximum room temperature: 122°F (T2) -> engine stop

If the actual methane number is lower than the specified, the knock control responds. First the ignition timing
is changed at full rated power. Secondly the rated power is reduced. These functions are carried out by the
engine management.

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Operation of Voltage and frequency outside of stated li mits for the generator as per IEC 60034-1 Zone A will
result in a power de-rate up to and including tripping of the equipment.

The generator set fulfills the limits for mechanical vibrations according to ISO 8528-9.
If possible, railway trucks must not be used for transport (TI 1000-0046).

Parameters for the operation of control unit and the electrical equipment

Relative humidity: 50%
Maximum temperature: 40°C.
Altitude: <2000m above the sea level.
The gas quantity indicated under the technical data ref ers to standard conditions with the given calorific
value. The actual volume flow (under operating conditions) has to be considered for dimensioning the gas
compressor and each gas feeding component – it will be affected by:
 Actual gas temperature (limiting temperature according to TI 1000-0300)
 Gas humidity (limiting value according to TI 1000-0300)
 Gas Pressure
 Biogas is based on 60% CH4, 40% CO2 unless otherwise detailed.

1.00 Scope of supply - Module
Design:
The module is built as a compact package. The engine base is bolted to the gearbox/generator base.
The Engine output shafting is connected through a coupling to a gearbox. A second coupling is then
provided connecting the gearbox to the generator. To provide the best possible isolation from the
transmission of vibrations, the engine rests on the engine base -frame by means of anti-vibration mounts. The
remaining vibrations are eliminated by mounting the complete module (engine and gearbox/generator
frames) on isolating pads (e.g. Sylomer). This, in principle, allows for placing of the module to be directly on
any floor capable of carrying the static load. No special foundation is required. Prevention of sound
conducted through solids has to be provided locally.

1.01 Spark ignited gas engine
Four-stroke, air/gas mixture turbocharged, aftercooled, with high performance ignition system and
electronically controlled air/gas mixture system.
The engine is equipped with the most advanced

LEANOX® LEAN-BURN COMBUSTION SYSTEM

developed by GE JENBACHER.

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1.01.01 Engine design (Air Start)
Engine block
Single-piece crankcase and cylinder block made of special casting; crank case covers for engine inspection,
welded steel oil pan.

Crankshaft and main bearings
Drop-forged, precision ground, surface hardened, statically and dynamically balanced; main bearings (upper
bearing shell: grooved bearing / lower bearing shell: sputter bearing) arranged between crank pins, drilled oil
passages for forced-feed lubrication of connecting rods.

Vibration damper
Maintenance free viscous damper

Flywheel
With ring gear for starter motor and additionally screwed on.

Pistons
Single-piece made of steel, with piston ring carrier and oil passages for cooling; piston rings made of high
quality material, main combustion chamber specially designed for lean burn operation.

Connecting rods
Drop-forged, heat-treated, big end diagonally split and toothed. Big end bearings (upper bearing shell: sputter
bearing / lower bearing shell: sputter bearing) and connecting rod bushing for piston pin.

Cylinder liner
Chromium alloy gray cast iron, wet, individually replaceable.

Cylinder head
Specially designed and developed for GE JENBACHER-lean burn engines with optimized fuel consumption
and emissions; water cooled, made of special casting, individually replaceable; Valve seats and valve guides
and spark plug sleeves individually replaceable; exhaust and inlet valve made of high quality material; Pre-
chamber with check-valve.

Crankcase breather
Connected to combustion air intake system

Valve train
Camshaft, with replaceable bushings, driven by crankshaft through intermediate gears, valve lubrication by
splash oil through rocker arms.

Combustion air/fuel gas system
Motorized carburetor for automatic adjustment according fuel gas characteristic. Exhaust driven turbocharger,
mixture manifold with bellows, water-cooled intercooler, throttle valve and distribution manifolds to cylinders.

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Ignition system
Most advanced, fully electronic high performance ignition s ystem, external ignition control.
MORIS: Automatically, cylinder selective registration and control of the current needed ignition voltage.

Lubricating system
Gear-type lube oil pump to supply all moving parts with filtered lube oil, pressure control valv e, pressure relief
valve and full-flow filter cartridges. Cooling of the lube oil is arranged by a heat exchanger.

Engine cooling system
Jacket water pump complete with distribution pipework and manifolds.

Exhaust system
Turbocharger and exhaust manifold

Exhaust gas temperature measuring
Thermocouple for each cylinder

Electric actuator
For electronic speed and output control

Electronic speed monitoring for speed and output control
By magnetic inductive pick up over ring gear on flywheel

Air Starter motor
Engine mounted air starter motor

1.01.02 Additional equipment for the engine (spares for commissioning)
The initial set of equipment with the essential spare parts for operation after commiss ioning is included in the
scope of supply.

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1.01.03 Engine accessories
Insulation of exhaust manifold:
Insulation of exhaust manifold is easily installed and removed

Sensors at the engine:
 Jacket water temperature sensor
 Jacket water pressure sensor
 Lube oil temperature sensor
 Lube oil pressure sensor
 Mixture temperature sensor
 Charge pressure sensor
 Minimum and maximum lube oil level switch
 Exhaust gas thermocouple for each cylinder
 Knock sensors
 Gas mixer / gas dosing valve position reporting.

Actuator at the engine:
 Actuator - throttle valve
 Bypass-valve for turbocharger
 Control of the gas mixer / gas dosing valve

1.01.04 Standard tools (per installation)
The tools required for carrying out the most important maintenance work are included in the scope of supply
and delivered in a toolbox.

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1.02 Generator-Medium Voltage

The 2 bearing generator consists of the main generator (built as rotating field machine), the exciter
machine (built as rotating armature machine) and the digital excitation system.
The digital regulator is powered by an auxiliary winding at the main stator or a PMG system

Main components:
 Enclosure of welded steel construction
 Stator core consist of thin insulated electrical sheet metal with integrated cooling channels.
 Stator winding with 5/6 Pitch
 Rotor consist of shaft with shrunken laminated poles, Exciter rotor, PMG (depending on Type) and fan.
 Damper cage
 Excitation unit with rotating rectifier diodes and overvoltage protection
 Dynamically balanced as per ISO 1940, Balance quality G2,5
 Drive end bracket with re greaseable antifriction bearing
 Non-drive end bracket with re grease antifriction bearing
 Cooling IC01 - open ventilated, air entry at n on-drive end, air outlet at the drive end side
 Main terminal box includes main terminals for power cables
 Regulator terminal box with auxiliary terminals for thermistor connection and regulator.
 Anti-condensation heater
 3 PT100 for winding temperature monitoring+3 PT100 Spare
 2 PT100 for bearing temperature monitoring
 Current transformer for protection and measuring in the star point
xx/1A, 10P10 15VA , xx/1A, 1FS5, 15VA

Electrical data and features:
 Standards: IEC 60034, EN 60034, VDE 0530, ISO 8528-3, ISO 8528-9
 Voltage adjustment range: +/- 10 % of rated voltage (continuous)
 Frequency: -6/+4% of rated frequency
 Overload capacity: 10% for one hour within 6 hours, 50% for 30 seconds
 Asymmetric load: max. 8% I2 continuous, in case of fault I2 x t=20
 Altitude: < 1000m
 Max permitted generator intake air temperature: 5°C - 40°C
 Max. relative air humidity: 90%
 Voltage curve THD Ph-Ph: <3% at idle operation and <3% at full load operation with linear symmetrical
load
 Generator suitable for parallel operating with the grid and other generators
 Sustained short circuit current at 3-pole terminal short circuit: minimum 3 times rated current for 5 seconds.
 Over speed test with 1.2 times of rated speed for 2 minutes according to IEC 60034

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Digital Excitation system ABB Unitrol 1010 mounted within the AVR Terminal box with following
features:

 Compact and robust Digital Excitation system for Continuous output current up to 10 A (20A Overload
current 10s)
 Fast AVR response combined with high excitation voltage improves the transient stability during LVRT
events.
 The system has free configurable measurement and analog or digital I/Os. The configuration is done via the
local human machine interface or CMT1000
 Power Terminals
3 phase excitation power input from PMG or auxiliary windings
Auxiliary power input 24VDC
 Excitation output
 Measurement terminals: 3 phase machine voltage, 1 phase network voltage, 1 phase machine current
 Analog I/Os: 2 outputs / 3 inputs (configurable), +10 V / -10 V
 Digital I/O: 4 inputs only (configurable), 8 inputs / outputs (configurable)
 Serial fieldbus: RS485 for Modbus RTU or VDC (Reactive power load sharing for up to 31 GEJ engines in
island operation), CAN-Bus for dual channel communication
 Regulator Control modes: Bump less transfer between all modes
Automatic Voltage Regulator (AVR) accuracy 0,1% at 25°C ambient temperature
Field Current Regulator (FCR)
Power Factor Regulator (PF)
Reactive Power Regulator (VAR)
 Limiters: Keeping synchronous machines in a safe and stable operation area
Excitation current limiter (UEL min / OEL max)
PQ minimum limiter
Machine current limiter
V / Hz limiter
Machine voltage limiter
 Voltage matching during synchronization
 Rotating diode monitoring
 Dual channel / monitoring: Enables the dual channel operation based on self -diagnostics and setpoint
follow up over CAN communication. As Option available
 Power System Stabilizer (PSS) is available as option. Compliant with the standard IEEE 421.5 -2005 2A /
2B, the PSS improves the stability of the generator over the highest possible operation range.
 Computer representation for power s ystem stability studies: ABB 3BHS354059 E01
 Certifications: CE, cUL certification according UL 508c (compliant with CSA), DNV Class B,

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 Commissioning and maintenance Tool CMT1000 (for trained commissioning/ maintenance personal)
 With this tool the technician can setup all parameters and tune the PID to guarantee stable operation. The
CMT1000 software allows an extensive supervision of the system, which helps the user to identify and
locate problems during commissioning on site. The CMT1000 is connected to the target over USB or
Ethernet port, where Ethernet connection allows remote access over 100 m.
 Main window
 Indication of access mode and device information.
 Change of parameter is only possible in CONTROL access mode.
 LED symbol indicates that all parameter are stored on none volatile memory.
 Setpoint adjust window
 Overview of all control modes, generator status, active limiters status and alarms.
 Adjust set point and apply steps for tuning of the PID.
 Oscilloscope
 4 signals can be selected out of 20 recorded channels. The time resolution is 50 ms.Save files to your PC
for further investigation.
 Measurement
 All measurements on one screen.

Routine Test
Following routine tests will be carried out by the generator manufacturer
 Measuring of the DC-resistance of stator and rotor windings
 Check of the function of the fitted components (e.g. RTDs, space heater etc.)
 Insulation resistance of the following components
Stator winding, rotor winding
Stator winding RTDs
Bearing RTDs
Space heater
 No Load saturation characteristic (remanent voltage)
 Stator voltage unbalance
 Direction of rotation, phase sequence
 High voltage test of the stator windings (2 x Unom. + 1000 V) and the rotor windings (min. 1500 V)

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1.03 Module Accessories
Base frame
Split Base Frame fabricated with welded structural steel. First frame to mount the engine, jacket water heat
exchangers, pumps and engine auxiliaries, the second to mount the gearbox and generator.

Coupling #1
Engine to Gearbox coupling is provided. The coupling isolates the major sub-harmonics of engine alternating
torque from gear box.

Coupling #2
Gearbox to Generator Coupling is provided. This coupling is designed with a torque limiter to couple gear
box with alternator.

Coupling housings
Provided for both Couplings

Anti-vibration mounts
2 sets of isolation, one is arranged between engine block assembly and base frame. The second is via
insulating pads (SYLOMER) for placement between base frame and foundation, delivered loose.

Gear box:
A Single-stage spur gear with overhead shaft and closed loop lube oil system, completely mounted on the
gearbox/generator base frame. The lube oil heat exchanger is integrated with the warm/cooling water circuit.
The gear transmission ratio is 1:1.2. Oil volume is approximately 52 gals (196 liters).

Exhaust gas connection
A flanged connection is provided that collects the exhaust gas turbocharger output flows, inc ludes flexible
pipe connections (compensators) to compensate for heat expansions and vibrations.

Combustion air filter
A Dry type air filter with replaceable filter cartridges is fitted. The assembly includes flexible connections to
the fuel mixer/carburetor and service indicator.

Interface panel (M1 cabinet)
Totally enclosed sheet steel cubicle with hinged doors, pre-wired to terminals, ready to operate. All Cable
entry will be via bottom mounted cable gland plates.

Painting: RAL 7035

Protection: External NEMA 3 (IP 54), Internal IP 20 (protection against direct contact with live parts)

Cabinet design is according to IEC 439-1 (EN 60 439-1/1990) and DIN VDE 0660 part 500, respectively.
Ambient temperature 41 - 104 °F (5 - 40 °C), Relative humidity 70%

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Dimensions:
 Height: 51 in - 82 in (1300 mm-2100 mm)
 Width: 40 in - 47 in (1000 mm -1200 mm)
 Depth: 16 in - 24 in (400 mm-600 mm)

Control Power Source: The starter batteries and the cabinet mounted battery chargers will provide the power
source for this enclosure.

Interface Panel contents and control functions:
 The cabinet houses the unit Battery Charger and primary 24VDC Control Power Distribution (breakers,
fuses, and terminals) from the unit Batteries
 Distributed PLC Input and Output cards, located in the cabinet, gather all Engine, Gearbox and Generator
Control I/O. These cards transmit data via data bus interface to the central engine control of the module
control panel located in the A1 cabinet. Data bus is via CAN and B&R Proprietary Data Highw ay (Data
Cables provided by GE)
 Speed monitoring relays for protection are provided.
 Gas Train I/O Collection, including interface relays and terminals for gas train shutoff valves.
 Transducer for generator functions, such as excitation voltage.
 Door Mounted Emergency Stop Switch with associated Emergency Stop Loop interface relays.
 Miscellaneous control relays, contacts, fuses, etc. for additional control valves, and auxiliaries.
 Interface Terminal Strips

Skid Mounted 3 Phase Devices are Powered by 3 x 480/277 V, 60 Hz, 50 A

AC Power for engine mounted auxiliaries (heater, pumps, etc.) are routed through a separate J -box mounted
on the side M1 cabinet (Box E1). This is done to maintain signal segregation (AC from control)

NOTE: Generator Current Transformer wiring is connected directly to the Generator and does NOT
pass through the M1 cabinet.

Exhaust gas scavenging blower
An exhaust gas scavenging blower is used to scavenge the remaining exhaust gas out of the exhaust gas
pipe work, to prevent the appearance of deflagrations.

Function:
Before each start scavenging by blower is done for app. 1 minute (except at black out – start)

Supervisions:
 Scavenging air fan failure
 Scavenging air flap failure

Consisting of:
 Fan
 Exhaust gas flap
 Temperature switch
 Compensator and pipe work

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1.03.01 Engine jacket water system
Engine jacket water system
Closed cooling circuit, consisting of:
 Expansion tank
 Filling device (check and pressure reducing valves, pressure gauge)
 Safety valve(s)
 Thermostatic valve
 Required pipework on module
 Vents and drains
 Electrical jacket water pump, including check valve
 Jacket water preheat device

1.03.02 Automatic lube oil replenishing system incl. extension tank
Automatic lube oil replenishing system:
Includes float valve in lube oil feed line, including inspection glass. Electric monitoring system will be provided
for engine shut-down at lube oil levels "MINIMUM" and "MAXIMUM". Solenoid valve in oil feed line is only
activated during engine operation. Manual override of the solenoid valve, for filling procedure during oil
changes is included.

Oil drain
By set mounted cock

Oil sump extension tank (delivered loose) 79.3 gal
To increase the time between oil changes

Pre-lubrication- and aftercooling oil pump:
Mounted on the module base fram e; it is used for pre-lubrication and aftercooling of the turbochargers.
Period of operation: Pre-lubrication: 1 minute both pumps
Aftercooling: 15 minutes from engine stop only the 480/277 V pump
Consisting of:
 1 piece oil pump 1500 W, 480/277 V
 1 piece oil pump 1500 W, 24 V
 All necessary vents
 Necessary pipework

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1.04 Heat recovery
Engine-mounted intercooler and lube oil heat exchanger; jacket water heat exchanger mounted to the engine
res. to the module base frame, complete with interconnecting pipe work.
The exhaust gas heat exchanger is mounted to the heat recovery module.
The insulation of heat exchangers and pipework is not included in GE Jenbacher scope of supply.

Heat exchanger - air/fuel mixture to warm water (intercooler)
The engine-mounted intercooler is of two stage design. The first stage is integrated with the warm water
circuit. The second stage requires low temperature water.

Heat exchanger - lube oil to water
The engine mounted lube oil heat exchanger is not integrated. The heat must be taken away by a separate
cooling circuit.

Heat exchanger - engine jacket water to warm water
Mounted to module base frame complete with interconnecting pipe work, for recovery of engine jacket water
heat.

1.05a Gas train (Biogas)
Pre-assembled, delivered loose, for installation into gas pipework to the engine.

Consisting of:
 Main Biogas gas train:
 Manual shut off valve
 Gas filter, filter to <3 µm
 Adapter with dismount to the pre-chamber gas train
 Gas admission pressure regulator
 Pressure gauge with push button valve; 0-7.25 psi (0-500 mbar)
 Solenoid valves
 Gas pressure switch (min.)
 Leakage detector
 Gas pressure regulator
 TEC JET (has to be implemented horizontal)

The gas train complies with DIN - DVGW regulations.

Maximum distance from TEC JET outlet to gas entry on engine, including flexible connections, is 39.37 in (1
m). Reference GE Jenbacher Technical Instruction TI 1510-0064 for Tec Jet and Gas Train installation
details

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1.05b Gas train (Natural Gas)
Pre-assembled, delivered loose, for installation into gas pipework to the engine.

Consisting of:
 Main Natural Gas train:
 Manual shut off valve
 Gas filter, filter to <3 µm
 Adapter with dismount to the pre-chamber gas train
 Gas admission pressure regulator
 Pressure gauge with push button valve; 0-7.25 psi (0-500 mbar)
 Solenoid valves
 Gas pressure switch (min.)
 Leakage detector
 Gas pressure regulator
 TEC JET (has to be implemented horizontal)

The gas train complies with DIN - DVGW regulations.

Maximum distance from TEC JET outlet to gas entry on engine, including flexible connections, is 39.37 in (1
m). Reference GE Jenbacher Technical Instruction TI 1510-0064 for Tec Jet and Gas Train installation
details

1.05c Pre-chamber Gas train (Natural Gas)
Pre-assembled, delivered loose, for installation into gas pipework to the engine.

Consisting of:
 Pre-chamber gas train:
 Manual shut off valve
 Gas filter, filter fineness <3 µm
 Solenoid valves
 Pressure regulator
 Calming distance with reducer
 Pressure gauge with push button valve; 0-72.5 psi (1-5 bar)

Pre chamber gas pressure regulator (incl. stabilization section) assembled at the flexible connection pre
chamber gas.

Use of fuel other than Natural Gas in Prechamber to be noted.

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1.07 Painting
 Quality: Oil resistant prime layer
Synthetic resin varnish finishing coat

 Color: Engine: RAL 6018 (green)
Base frame: RAL 6018 (green)
Generator: RAL 6018 (green)
Module interface
panel: RAL 7035 (light grey)
Control panel: RAL 7035 (light grey)

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1.11 Engine generator control panel per module- Dia.ne XT4 incl. Single
synchronization of the generator breaker
Dimensions:
 Height: 87 in (including 8 in pedestal *)
 Width: 32 -48 in*)
 Depth: 24 in *)

Protection class:
 external IP42
 Internal IP 20 (protection again direct contact with live parts)

*) Control panels will be dimensioned on a project specific basis. Actual dimensions will be provided i n the
preliminary documentation for the project.

Control supply voltage from starter and control panel batteries: 24V DC

Auxiliaries power supply: (from provider of the auxiliary supply)
3 x 480/277 V, 60 Hz

Consisting of:
Motor - Management - System DIA.NE

Setup:
 a) Touch display visualization
 b) Central engine and unit control

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Touch Display Screen:

15“ Industrial color graphic display with resistive touch.

Interfaces:
 24V voltage supply
 VGA display connection
 USB interface for resistive touch

Protection class of DIA.NE XT panel front: IP 65
Dimensions: W x H x D = approx. 16x12x3in

The screen shows a clear and functional summary of the measurement values and simul taneously shows a
graphical summary.

Operation is via the screen buttons on the touch screen
Numeric entries (set point values, parameters…) are entered on the touch numeric pad or via a scroll bar.
Determination of the operation mode and the method of synchronization via a permanently displayed button
panel on the touch screen.

Main screens (examples):

Main: Display of the overview, auxiliaries status, engine start and operating data.

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ELE: Display of the generator connection with electrical measurement values and synchronization status

OPTION: Generator winding and bearing temperature
Trending
Trend with 100ms resolution

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Measurement values:
 510 data points are stored
 Measurement interval = 100ms
 Raw data availability with 100ms resolution: 24 hours + max. 5.000.000 changes in value at shut down
(60 mins per shut down)
 Compression level 1: min, max, and average values with 1000ms resolution: 3 days
 Compression level 2: min, max, and average values with 30s resolution: 32 days
 Compression level 3: min, max, and average values with 10min resolution: 10 years

Messages:
10.000.000 message events

Actions (operator control actions):
1.000.000 Actions

System messages:
100.000 system messages

Central engine and module control:

An industrial PC- based modular industrial control system for module and engine sequencing control (start
preparation, start, stop, aftercooling and control of auxiliaries) as well as all control functions.

Interfaces:
 Ethernet (twisted pair) for remote monitoring access
 Ethernet (twisted pair) for connection between engines
 Ethernet (twisted pair) for the Powerlink connection to the control input and output modules.
 USB interface for software updates

Connection to the local building management system according t o the GE Jenbacher option list
(OPTION)
 MODBUS-RTU Slave
 MODBUS-TCP Slave,
 PROFIBUS-DP Slave (160 words),
 PROFIBUS-DP Slave (190 words),
 ProfiNet
 OPC

Control functions:
 Speed control in idle and in island mode
 Power output control in grid parallel operation, or according to an internal or external set point value on a
case by case basis
 LEANOX control system which controls boost pressure according to the power at the generator terminals,
and controls the mixture temperature according to the engine driven air-gas mixer

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 Knocking control: in the event of knocking detection, ignition timing adjustment, power reduction and
mixture temperature reduction (if this feature is installed)
 Load sharing between engines in island mode operation (option)
 Linear power reduction in the event of excessive mixture temperature and misfiring
 Linear power reduction according to CH4 signal (if available)
 Linear power reduction according to gas pressure (option)
 Linear power reduction according to air intake temperature (option )

Multi-transducer to record the following alternator electrical values:
 Phase current (with slave pointer))
 Neutral conductor current
 Voltages Ph/Ph and Ph/N
 Active power (with slave pointer)
 Reactive power
 Apparent power
 Power factor
 Frequency
 Active and reactive energy counter

Additional 0 (4) - 20 mA interface for active power as well as a pulse signal for active energy

The following alternator monitoring functions are integrated in the multi-measuring device:
 Overload/short-circuit [51], [50]
 Over voltage [59]
 Under voltage [27]
 Asymmetric voltage [64], [59N]
 Unbalance current [46]
 Excitation failure [40]
 Over frequency [81>]
 Under frequency [81<]

Lockable operation modes selectable via touch screen:
 "OFF" operation is not possible, running units will shut down immediately;
 "MANUAL" manual operation (start, stop) possible, unit is not available for fully automatic
operation.
 "AUTOMATIC" fully automatic operation according to external demand signal:

Demand modes selectable via touch screen:
 external demand off („OFF“)
 external demand on („REMOTE“)
 overide external demand („ON“)

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Malfunction Notice list:

Shut down functions e.g.:
 Low lube oil pressure
 Low lube oil level
 High lube oil level
 High lube oil temperature
 Low jacket water pressure
 High jacket water pressure
 High jacket water temperature
 Overspeed
 Emergency stop/safety loop
 Gas train failure
 Start failure
 Stop failure
 Engine start blocked
 Engine operation blocked
 Misfiring
 High mixture temperature
 Measuring signal failure
 Overload/output signal failure
 Generator overload/short circuit
 Generator over/undervoltage
 Generator over/underfrequency
 Generator asymmetric voltage
 Generator unbalanced load
 Generator reverse power
 High generator winding temperature
 Synchronizing failure
 Cylinder selective Knocking failure

Warning functions e.g.:
 Cooling water temperature min.
 Cooling water pressure min.
 Generator winding temperature max.

Remote signals:
(volt free contacts)
1NO = 1 normally open
1NC = 1 normally closed
1COC = 1 change over contact

 Ready for automatic start (to Master control) 1NO
 Operation (engine running) 1NO
 Demand auxiliaries 1NO
 Collective signal "shut down" 1NC

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 Collective signal "warning" 1NC

External (by others) provided command/status signals:
 Engine demand (from Master control) 1S
 Auxiliaries demanded and released 1S

Single synchronizing Automatic

For automatic synchronizing of the module with the generator circuit breaker to the grid by PLC - technology,
integrated within the module control panel.

Consisting of:
 Hardware extension of the programmable control for fully automatic synchronization selection and
synchronization of the module and for monitoring of the generator circuit breaker closed signal.
 Lockable synchronization selection via touch screen with the following selection modes:
 "MANUAL" Manual initiation of synchronization via touch screen button followed by fully
automatic synchronization of the module
 "AUTOMATIC" Automatic module synchronization, after synchronizing release from the module
control
 "OFF" Selection and synchronization disabled
Control of the generator circuit breaker according to the synchronization mode select ed via touch
screen.
 "Generator circuit breaker CLOSED/ Select" Touch-button on DIA.NE XT
 "Generator circuit breaker OPEN" Touch-button on DIA.NE XT

Status signals:
Generator circuit breaker closed
Generator circuit breaker open

Remote signals:
(volt free contacts)
Generator circuit breaker closed 1 NO

The following reference and status signals must be provided by the switchgear supplier:

 Generator circuit breaker CLOSED 1 NO
 Generator circuit breaker OPEN 1 NO
 Generator circuit breaker READY TO CLOSE 1 NO
 Mains circuit breaker CLOSED 1 NO
 Mains circuit breaker OPEN 1 NO

Mains voltage 3 x 4160V or 3x 110V/v3 - other measurement voltages available on request
Bus bar voltage 3 x 4160 V or 3x 110V/v3 – other measurement voltages available on request
Generator voltage 3 x 4160 V or 3x 110V/v3 – other measurement voltages available on request

Voltage transformer in the star point with minimum 50VA and Class 0,5

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The following volt free interface-signals will be provided by GE Jenbacher to be incorporated in
switchgear:

 CLOSING/OPENING command for generator circuit breaker
(permanent contact) 1 NO + 1 NC
 Signal for circuit breaker undervoltage trip 1 NO

Maximum distance between module control panel and engine/interface panel: 99ft
Maximum distance between module control panel and power panel: 164ft
Maximum distance between module control panel and master control panel: 164ft
Maximum distance between alternator and generator circuit breaker: 99ft

1.11.01 Remote messaging over MODBUS-TCP
Data transfer from the Jenbacher module control system to the customer's on -site central control system via
MODBUS TCP using the ETHERNET 10 BASE-T/100BASE-TX protocol TCP/IP.

The Jenbacher module control system operates as a SLAVE unit.
The data transfer via the customer's MASTER must be carried out in cycles.

Data transmitted:
Individual error messages, operational messages, measured values for generator power, o il pressure, oil
temperature, cooling water pressure, cooling water temperature, cylinder and collective exhaust gas
temperatures.

GE Jenbacher limit of supply:
RJ45 socket at the interface module in the module control cabinet

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1.11.06 Remote Data-Transfer with DIA.NE XT4
General
DIA.NE XT4 offers remote connection with Ethernet.

Applications:

1.) DIA.NE XT4 HMI
DIA.NE XT4 HMI is the human-machine-interface of DIA.NE XT4 engine control and visualization system for
GE Jenbacher gas engines.
The system offers extensive facilities for commissioning, monitoring, servicing and analysis of the site.
By installation of the DIA.NE XT4 HMI client program it can be used to establish connection to site, if
connected to a network and access rights are provided.
The system runs on Microsoft Windows Operating systems (Windows XP, Windows 7, Windows 8)

Function
Functions of the visualization system at the engine control panel can be used remotely. These are among
others control and monitoring, trend indications, alarm management, parameter management, and access to
long term data recording. By providing access to multiple systems, also with multiple clients in parallel,
additional useful functions are available like multi-user system, remote control, print and export functions and
data backup.DIA.NE XT4 is available in several languages.

Option - Remote demand/blocking

If the service selectors switch at the module control panel is in pos."Automatic" and the demand -selector
switch in pos."Remote", it is possible to enable (demanded) or disable (demand off) the module wit h a control
button at the DIA.NE XT4 HMI
Note:
With this option it makes no sense to have an additional clients demand (via hardware or data bus)
or a self-guided operation (via GE Jenbacher master control, grid import /export et c.).

Option - Remote - reset (see TA-No. 1100-0111 chapter 1.7 an d1.9)

Scope of supply
 Software package DIA.NE XT4 HMI Client Setup (Download)
 Number of DIA.NE XT4 HMI - Client user license (Simultaneous right to access of one user to the
engine control)

Nr. of license Access
1 1 Users can be logged in at the same time with a PC
(Workplace, control room or at home).
2 - “n“ (Optional) 2- “n” Users can be logged in at the same time with a PC
(Workplace, control room or at home).
If 2- “n” users are locally connected at Computers from office
or control room, then it is not possible to log in from home.

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Caution! This option includes the DIA.NE XT4 HMI client application and its license only – NO secured,
encrypted connection will be provided by GE Jenbacher! A secured, en crypted connection – which is
mandatory – has to be provided by the customer (via LAN connection or customer-side VPN), or can be
realized by using option myPlant™.

Customer requirements
 Broad band network connection via Ethernet(100/1000BASE-TX) at RJ45 Connector (ETH3) at
DIA.NE XT4 server inside module control panel
 Standard PC with keyboard, mouse or touch and monitor (min. resolution 1024*768)
 Operating system Windows XP, Windows 7, Windows 8
 DirectX 9.0 c compatible or newer 3D display adapter wit h 64 MB or higher memory

2.) myPlant™

myPlant™ is the GE Jenbacher remote monitoring and diagnostic (RM&D) service

Offering Feature Connect Protect
Asset
Management
Online data transfer 
Big Data cloud storage 
Engine status visibility 
Control alarms visibility 
Basic data trends 
Remote access to DIA.NE HMI - 
Unlimited data trending - 
Advanced diagnostics - 
WINSERVER Protection Plan - 
Fleet
Management
Fleet status on world map - 
Fleet summaries and reporting - 
Mobility SMS/Email notifications - 
Smartphone app 

Web application with following features:
 Visualization of the current state of the engine (available, in operation, fault)
 View of various readings of the Gen-set
 Visualization of counts as a trend graph (if plant available online, or by manually entering of the counter
readings)
 Trend graph of the performance value (low resolution; only if system available online)

myPlant™ Connect is free of charge for registered customers
myPlant™ Protect is free of charge within the warranty period and is also included as part of any contractual
service agreement (CSA).

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Scope of supply
 Access to myPlant™ Discovery version for up to 4 users
 Connection between plant server and myPlant™ system

Customer requirements
 Permanent Internet line (wired or mobile, (see option 4))
 See technical instruction TA 2300-0008
 Outbound data connectivity (from plant server to Internet) ONLY – INBOUND connections must NOT
be allowed!

CAUTION!
It is in the responsibility of the customer to prevent direct access from the Internet to the plant server using
technical equipment like firewalls.
GE Jenbacher does not provide such security devices and services as part of this option!

3.) myPlant™ notification service

Automatic alarm notification system for myPlant™ - enabled DIA.NE XT systems (all versions).

Function
 Automatic transfer of engine messages to the customer via email or SMS in case of engine trip, engine
start/stop or connectivity loss.

Scope of supply
 Feature of myPlant™ web portal

Customer requirements
 Engine must be connected to the myPlant™ system via Internet connection

myPlant™ notification is free of charge within the warranty period and is also included as part of any
contractual service agreement (CSA).

4.) Mobile Internet (OPTION)
Connection Plant - Customer via secured Internet - connection
See also technical instruction TA 2300 - 0006

Scope of delivery
 Mobile Internet router with antenna to connect to the DIA.NE Server XT4

Customer requirements
 SIM card for 3G / 4G

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5.) Network overview

For information only!

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1.11.14 Generator Overload / Short Circuit Protection
ANSI Function Code 50/51

Digital protection relay, 3-phase, integrated into the module control panel.
Connected to the protective current transformers in the generator star point
Acting on the generator circuit breaker and on the generator de-excitation
Alarm message on the DIA.NE screen

Characteristics / settings:
 Setting for overload: to 1,1 times of the generating set rated current,
 Dependent time characteristic acc. to IEC 60255-151: very inverse, time multiplier setting 0,6.
 Setting for short circuit: to 2,0 times of generating set rated current,
 Independent time characteristic: 300 ms (800 ms when dynamic network support).

1.11.15 Generator Differential Protection
ANSI function code 87

Digital protection relay, 3-phase, integrated into the module control panel.
Connected to the protective current transformers in the generator star point (GEJ scope of supply) and to the
protective current transformers in the generator circuit breaker panel (current transformers by client,
secondary 1A, optionally: 5A).
Acting on the generator circuit breaker and on the generator de-excitation
Alarm message on the DIA.NE screen

In plants with a unit generator-transformer configuration the protection is realized as generator/transformer
differential protection.

1.11.16 Generator Earth Fault Protection (nondirectional)
Digital protection relay, integrated into the module control panel.
Acting on the generator circuit breaker and on the generator de-excitation
Alarm message on the DIA.NE screen

Dependent on the generator grounding method one of the following protection functions is applied:
1) ANSI function code 50N/G
Detection of the earth fault current e.g. by means of a window-type current transformer
(Current transformer by client, secondary 1A, optionally: 5A).
2) ANSI function code 59N/G
Detection of the residual voltage e.g. by means of the voltage measured across the broken -delta
secondary windings of grounded voltage transformers (voltage transformers by client)

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1.11.31 Interfaces to customer Master synchronization
(Synchronization of grid CB)
Scope:
Interfaces from/to each module control panel and customer Master panel with potential free c ontacts.
Further project specific interfaces must be checked during project phase

The engines can run in island mode according to technical instruction TA 2108-0031 based on the condition
that island mode function of the control system is properly designed, supplied, installed and commissioned by
the customer in accordance with GE Jenbacher requirements.

Request to customer master synchronization:

Manual synchronization
For manual synchronization a "synchronizing check relay" is necessary.

Signal monitoring
The synchronizing panel has to have monitoring to detect unlogical signals and operations (such as trip
errors) to ensure safe operation.

Grid protection device (supplied locally):
Protections and settings must be according to GE requirements

Max. distance between customer Master synchronization panel and GE Module control panel: 164 ft

Scope of supply GE Jenbacher:
Terminals at each module control panel.

1.20.03 Start System (Air Start)
Pneumatic Start System:
6.2 bar (90 psig) Starter Motor requiring 2730 Nm3/hr (1610 scft/min) for 10 minutes.

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1.20.04 Battery System
Battery (is not included in GE Jenbacher scope):
4 piece 12 V Pb battery, 160 Ah (according to DIN 72311), complete with cover plate, terminals and acid
tester.

Battery voltage monitoring:
Monitoring by an under voltage relay.

Battery charging equipment:
Capable for charging the starter battery with I/U characteristic and for the supply of all connected D.C.
consumers.
Charging device is mounted inside of the module interface panel or module control panel.

 General data:
 Power supply 3 x 320 - 550 V, 47 - 63 Hz
 max. power consumption 1060 W
 Nominal D.C. voltage 24 V (+/-1%)
 Voltage setting range 24 V to 28,8V (adjustable)
 Nominal current (max.) 40 A
 Dimensions ca. 10 x 5 x 5 inch (240 x 125 x 125 mm)
 Degree of protection IP20 to IEC 529
 Operating temperature 32 °F – 140 °F (0 °C - 60 °C)
 Protection class 1
 Humidity class 3K3, no condensation.
 Natural air convection
 Standards EN60950,EN50178
UL/cUL (UL508/CSA 22.2)
Signalling:
Green Led: Output voltage > 20,5V
Yellow Led: Overload, Output Voltage < 20,5V
Red Led: shutdown

Control accumulator:
 Pb battery 24 VDC/18 Ah

1.20.05 Electric jacket water preheating
Installed in the jacket water cooling circuit, consisting of:
 Heating elements
 Water circulating pump

The jacket water temperature of a stopped engine is maintained between 133 °F (56°C) and 140°F (60°C), to
allow for immediate loading after engine start.

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1.20.08 Flexible connections
Following flexible connections per module are included in the GE Jenbacher -scope of supply:

No.Connection Unit Dimension Material

2 Warm water in-/outlet in/lbs 4''/145 Stainless steel
1 Exhaust gas outlet in/lbs 20''/145 Stainless steel
1 Fuel gas inlet in/lbs 4-6''/232 Stainless steel
2 Intercooler in-/outlet in/lbs 2½''/ Stainless steel
2 Lube oil connection in 1.1 Hose

Seals and flanges for all flexible connections are included.

1.20.45 Fuel Blending
As a prerequisite to any discussions regarding on online fuel blending, both gases must comply with GE
Jenbacher TI 1000-0300.

Physically, the engine must be installed with two Tec Jet based gas train systems sized as required. To
function properly, each individual gas train should be able to provide the full fuel flow required to maintain
rated load of the engine generator set. If 0-100% blending on each fuel is specified, the technician must have
the capability to operate the engine on each fuel (from Start to Full Load) independently. Intermediate or
partial blending can be done by request.

From a controls perspective, the customer must provide the following Dual Fuel Blending signals (at a
minimum)

1) Fuel Gas Selection - Discrete Contact Input to the Diane Control System that represents the fuel that
the unit will start with (1 = High Btu (Gas1), 0 = Low Btu (Gas2)).
2) Release for Gas Mixing – Discrete contact input to the Diane Control System that represents a
release of the fuel delivery system to operate in mixing mode. This signal is used in conjunction
with Mixing Percentage in order to establish the amount of fuel to mix.
3) Mixing Percentage – An Analog (4-20mA) input to the Diane Control System representing the
percentage of Gas 2 fuel to mix.

As prerequisite for blending, the following permissive conditions must be met

1) Breaker is Closed
2) Unit is operating in Leanox control (No Island Mode)
3) No Gas Train 1 Low Pressure
4) Gas Train 1 READY (internal health signal)
5) No Gas Train 2 Low Pressure

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6) Gas Train 2 Ready (internal health signal)
7) Mixing Percentage signal healthy

Fuel Transfers are not permitted as long as the health of each gas train is not clear or if Gas Pressure of the
other train is Low. Diane Warning alarm signals 3221 (Gas Train 1 Low Pressure) or 3222 (Gas Train 2 Low
Pressure) will be displayed if this is the case.

Provided the above permissive conditions are met, to activate mixing, Release for Gas Mixing must be
enabled. Once enabled, the engine will ramp to the mixing percentage specified by Mixing Percentage.
The transfer rate is 1.7% per second, or if the transfer is to 100% of the other fuel, expect a ramp time of 60
seconds to get from one fuel to the other. The mixing percentage can be adjusted at any time during mixing
operations (Release for Gas Mixing = 1). Should a fault occur, the fuel system will default to the gas
selected at start (based on Fuel Gas Selection contact status).

This percentage will be maintained throughout the load profile of the engine, provided there is sufficient
capacity of the second fuel to maintain the load setpoint. Should there be insufficient fuel to maintain the KW
setpoint, a Low Pressure Alarm will occur and the unit will transfer back to the base fuel as dictated by the
position of the Fuel Gas Selection contact.

2.00 Electrical equipment
Totally enclosed floor mounted sheet steel cubicle with front door wired to terminals. Ready to operate, with
cable entry at bottom. Naturally ventilated.

Protection: IP 42 external, NEMA 12
IP 20 internal (protection against direct contact with live parts)

Design according to EN 61439-2 / IEC 61439-2 and ISO 8528-4.
Ambient temperature 41 - 104 °F (5 - 40 °C), 70 % Relative humidity

Standard painting: Panel: RAL 7035
Pedestal: RAL 7020

2.02 Grid monitoring device
Standard without static Grid - 60Hz alternator

Function:
For immediate disconnection of the generator from the grid in case of grid failures.

Consisting of:
 High/low voltage monitoring
 High/low frequency monitoring
 Specially adjustable independent time for voltage and frequency monitoring

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 Vector jump monitoring or df/dt monitoring for immediate disconnection of the generator from the grid for
example at short interruptions
 Indication of all reference dimensions for normal operation and at the case of disturbance over LCD and
LED
 Adjusting authority through password protection against adjusting of strangers

Scope of supply:
Digital grid protection relay with storage of defect data, indication of reference dimensio ns as well as
monitoring by itself.

Grid protection values:
Parameter Parameter limit Max time delay[s] Comments
59-61Hz Do work normal
f<[ANSI 81U] 59Hz 0,5 Load reduction with 10%/HZ
below 59Hz!
f<<[ANSI 81U] 58.5Hz 0,1
f>[ANSI 81O] 61,5Hz 0,1 Load reduction with 30%/HZ
above 61Hz!
U<[ANSI 27] 90% 1 Load reduction with 1%P
/%U below 95%
U<<[ANSI 27] 80% 0,2 Load reduction with 1%P
/%U below 95%
U>[ANSI 59] 110% 30 Load reduction with 1%P
/%U above 105%
U>>[ANSI 59] 115% 0,2 Load reduction with 1%
P/%U above 105%
Df/dt [ANSI 81R]
Or
Vector shift
[ANSI 78]
2Hz/s, 5 Periods
Or
8° -3pol

Cos phi range:
0,8ind (overexcited)
- 1

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2.12 Gas warning device
Function:
The gas warning device continuously monitors the radiated air in the engine room and warns against gases
which are injurious to persons’ health and against explosive gas concentrations.
The measuring head (catalytic sensor) is attached on the covering or nearby the ground, dependent upon the
gas source.

Scope of supply:
 Alarm unit voltage: 24VDC
 2 Gas sensor(s)

2.13 Smoke warning device
Function:
The smoke warning device in combination with the optical smoke detector (installed in the control room) and
the thermal smoke detector (installed in the engine room) provide extensive early warning signal.

Design:
The device has an optical display for alarm and operation.
The smoke warning device is installed in a plastic housing.

Scope of supply:
 Alarm unit voltage: 24 V
2 Smoke detector(s)

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3.70 Control Strategy and Options
Control Strategy -

Grid Parallel with KW Control – Real Power Load Control of the Generator set will be either via a 4-20mA
input from the customer representing a unit KW load setpoint or a KW load setpoint entered on the Diane
XT3 screen. Upon breaker closure, the unit will ramp to the setpoint at a maximum rate of
(Rated Unit KW) / 180 seconds.

Grid Parallel with PF Control – Reactive Power Load Control of the Generator set will be either via a 4-20mA
input from the customer representing a unit Power Factory setpoint or a Power Factor setpoint entered on the
Diane XT4 screen. Upon breaker closure, the unit will maintain the setpoint.

Grid Parallel with Import/Export Control - Load Control via an Import/Export KW level entered on the Diane
XT4 screen. Required will be a customer 4-20mA signal representing the Site KW (Imported and/or Exported
Power) that is to be controlled. Upon breaker closure, the unit will ramp to a load that will drive the KW value
represented by the 4-20mA input signal to the level entered on Customer Import/Export Setpoint entered in
the Diane XT4 screen. Once at the setpoint, the unit will raise and lower load to maintain this value. If the
generator load required to maintain this setpoint drops below the minimum load level of the generator set, the
unit 52G circuit breaker will be opened.

Grid Parallel with Fuel Gas Supply Pressur e Control - Load Control via Fuel Gas pressure level entered on
the Diane XT4 screen. Required will be a customer 4-20mA signal representing the Fuel Gas Supply
Pressure to the engine that is to be controlled. Upon breaker closure while running against t he utility, the unit
will ramp to a load that will maintain the supply pressure at or above the value represented by the setpoint
entered in the Diane XT4 screen. Should the setpoint be reached, no further load will be added so as to not
drive the pressure lower. If the pressure begins to drop, the unit will offload to maintain the setpoint. If the
pressure increases, the engine load will increase. Should the generator load required to maintain this
setpoint drop below the minimum load level of the generator set, the unit 52G circuit breaker will be opened.

Island Mode Operations with Blackout Starting – Island Operations with Black start capability will allow the
engine to start and run without utility being present. The engine will be able to start t he engine on battery
power, close the generator breaker against a dead bus, and operate independently of a utility power source.
The customer must ensure that there is sufficient fuel gas and pre-chamber gas at pressure in the event of a
Type 6 engine so configured. The engine will start without the normal confirmation of engine block
temperature or operation of a circulating AC water pump. It will be required of the operators that once the
engine is connected to the generator bus, power to the engine auxiliaries be restored. Load Management is
expected to be limited by the operators to the limits of the engine, as per GE Jenbacher TI 2108 -0031. This
system will work in conjunction with a GE Jenbacher Master Synchronizing Control (see appropriate Spec
Section) if so equipped, or a customer Master Synchronizing Panel as per 1.11.31.

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Per Unit Customer Enclosure Controls - Diane XT4 System will be provided with the following additional
features to operate a customer enclosure

- Audible and Visual Alarm Indications - Hardware and software to drive a customer provided horn
and strobe. Power for these devices is provided from the control system and is 24VDC

- Discrete Input for Air Filter Differential Pressure – Additional Discrete Input and associated software
for control

Per Unit Balance of Plant Controls – Hot Water Loop Panel Controls and Software to include:

- Hot Water Pump (Panel Control Parts and SW Only) - The option will add specific contact output and
feedback input to/from an MCC for the Hot Water Pump. This will include relays and software.

- Hot Water Return Temperature Control (Panel Parts and SW Only) - This feature will provide all
necessary controls to operate a 3 Way temperature control valve. The customer will provide a
PT100 as a feedback signal and the Diane will provide a 4-20mA Analog Output to a customer
provided valve. Control and Display Software are also provided.

- Emergency Hot Water Temperature Control (Panel Parts and SW Only) - This feature will provide all
necessary controls to operate a 3 Way temperature control valve. The customer will provide a
PT100 as a feedback signal and the Diane will provide a 4-20mA Analog Output to a customer
provided valve. Control and Display Software are also provided.

- Emergency Hot Water Pump Control (Panel Parts and SW Only) - The option will add specific contact
output and feedback input to/from an MCC for the Emergency Cooling System Pump. This will
include relays and software.

Per Unit Balance of Plant Controls – Intercooler Loop Panel Controls and Software to include:

- IC Temperature Control (Panel Parts and SW Only) - This feature will provide all necessary controls
to operate a 3 Way temperature control valve in the IC Loop if Not Required by Site Conditions. The
Diane will provide a 4-20mA Analog Output to a customer provided valve and will utilize mixture
temperature as a feedback input. Control and Display Software are also provided.

- Intercooler Pump Control (Panel Control Parts and SW Only) - The option will add specific contact
output and feedback input to/from an MCC for the Intercooler Water Pump. This will include relays
and software.

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Additional Control Signals for Display -

- Additional Analog Inputs for Display (4-20mA) – 5x

- Additional Analog Inputs for Display (PT100) – 5x

- Additional Analog Inputs for Display (Type K T/C) – 5x

Additional Options

- M1 Air Conditioner Unit

3.71 Vibration Sensor
A structural Vibration Sensor will be installed on the package base frame to detect excessive vibrations. A
signal we will sent to the control panel to indicate an alarm condition.

3.72 Seismic Protection
The main base will be supplied with pre-drilled holes to accommodate customer furnished bolts to act as
retaining elements in the event of an earthquake. The customer foundation mounted bolts cannot come into
contact with the unit base frame, as these bolts are for retention only, not mounting.

Details will be provided at first drawing submittal.

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4.00 Delivery, installation and commissioning
4.01 Carriage
According to contract.

4.02 Unloading
Unloading, moving of equipment to point of installation, mounting and adjustment of delivered equipment on
intended foundations is not included in GE Jenbacher scope of supply.

4.03 Assembly and installation
Assembly and installation of all GE Jenbacher -components is not included in GE Jenbacher scope of supply.

4.04 Storage
The customer is responsible for secure and appropriate storage of all delivered equipment.

4.05 Start-up and commissioning
Start-up and commissioning with the GE Jenbacher start -up and commissioning checklist is not included.
Plants with island operation require internet connection.

4.06 Trial run
After start-up and commissioning, the plant will be tested in an 8-hour trial run. The operating personnel will
be introduced simultaneously to basic operating procedures.
Is not included in GE Jenbacher scope of supply.

4.07 Emission measurement (exhaust gas analyser)
Emission measurement by GE Jenbacher personnel, to verify that the guaranteed toxic agent emissions have
been achieved (costs for measurement by an independent agency will be an extra charge).

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5.01 Limits of delivery
Electrical
 Module:
 At terminals of module interface panel
 At terminals of generator terminal box
(screwed glands to be provided locally)
 Module control panel:
At terminal strips
 Auxiliaries:
At terminals of equipment which is supplied separately

Warm water
 At inlet and outlet flanges on module
 At inlet and outlet flanges of the exhaust gas heat recovery system

Low temperature water
At inlet and outlet flanges at module

Exhaust gas
 At the exhaust gas exit of the engine
 At inlet and outlet flanges of the exhaust gas heat recovery system

Combustion air
The air filters are set mounted

Fuel gas
 At inlet and outlet flanges of gas train
 At inlet flange of gas pipework on module
 At outlet flange of the pre-chamber gas train
 At inlet flange of pre-chamber gas pipework on module
 At connection for boost pressure compensation on module
 At connection for boost pressure compensation on gas pressure regulator of the pre -chamber gas train

Lube oil
At lube oil connections on module

Draining connections and pressure relief
At module

Condensate
At condensate drain on exhaust gas heat exchanger

Insulation
Insulation of heat exchangers and pipe work is not included in our scope of supply and must be provided
locally.

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First filling
The first filling of the plant, (lube oil, engine jacket water, anti-freeze, anti-corrosive agent, battery acid) is not
included in our scope of supply.

The composition and quality of the used consumables are to be strictly monitored in accordance with the
"Technical Instructions" of GE JENBACHER.

Suitable bellows and flexible connections must be provided locally for all connections.
Cables from the module must be flexible.

5.02 Factory tests and inspections
The individual module components shall undergo the following tests an d inspections:

5.02.01 Engine tests
Carried out as combined Engine- and Module test according to DIN ISO 3046 at GE Jenbacher test bench.
The following tests are made at 100%, 75% and 50% load, and the results are reported in a test certificate:
 Engine output
 Fuel consumption
 Jacket water temperatures
 Lube oil pressure
 Lube oil temperatures
 Boost pressure
 Exhaust gas temperatures, for each cylinder

5.02.02 Generator tests
Carried out on the premises of the generator supplier.

5.02.03 Module tests
The engine will be tested with natural gas (methane number 94). The performance data achieved at the test
bench may therefore vary from the data as defined in the technical specification due to differences in fuel gas
quality.
Carried out as combined Engine- and Module test commonly with module control panel at GE Jenbacher test
bench, according to ISO 8528, DIN 6280. The following tests are made and the results are reported in a test
certificate:
Visual inspection of scope of supply per specifications.
 Functional tests per technical specification of control system.
 Starting in manual and automatic mode of operation
 Power control in manual and automatic mode of operation
 Function of all safety systems on module
 Measurements at 100%, 75% and 50% load:
 Frequency
 Voltage
 Current
 Generator output

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 Power factor
 Fuel consumption
 Lube oil pressure
 Jacket water temperature
 Boost pressure
 Mixture temperature
 Exhaust emission (NOx)

The module test for operating frequenzy 50 Hz and 6,3-6,6kV / 10,5kV-11kV will be carried out with the
original generator, except it is not possible because of the delivery date. Then a test generator will be used
for the module test.
To prove characteristics of the above components, which are not tested on the test bench by GE
JENBACHER, the manufacturers’ certificate will be provided.

5.03 Documentation
Preliminary documentation 60 days after receipt of a technically and commercially clarified order:
 Module drawing 1)
 Technical diagram 1)
 Drawing of control panel 3)
 List of electrical interfaces 2)
 Technical specification of control system 2)
 Technical drawing auxiliaries (if included in GE Jenbacher-limit of delivery) 1)

At delivery:
 Wiring diagrams 3)
 Cable list 3)

At start-up and commissioning (or on clients request):
 Operating and maintenance manual 4)
 Spare parts manual 4)
 Operation report log 4)

This page intentionally left blank.
Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

B
Use of contents on this sheet is subject to the limitations specified at the beginning of this document.
BACT Determination for Cogen Engines 3 and 4 TM - FINAL.docx
Attachment B: BACT Database Search Results

Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

B
Use of contents on this sheet is subject to the limitations specified at the beginning of this document.
BACT Determination for Cogen Engines 3 and 4 TM - FINAL.docx

This page intentionally left blank.

Attachment B
Facility 1 Facility 2 Facility 3 Facility 4 Facility 5 Facility 6 Facility 7 Facility 8 Facility 9 Facility 10 Facility 11 Facility 12 Facility 13 Facility 14 Facility 15 Facility 16 Facility 17 Facility 18
Air District Maine DEP Vermont DEC Indiana DEM Michigan DEQ Illinois EPA Florida DEP Michigan DEQ San Diego County APCD Oregon DEQ Oregon DEQ Vermont DEC Michigan DEQ Michigan DEQ Michigan DEQ Indiana DEM Ohio EPA Santa Barbara County APCD Ohio EPA
County, State Penobscot, ME Orleans, VT White, IN Macomb, MI Ogle, IL Sarasota, FL Lennon, MI San Diego, CA Gilliam, OR Gilliam, OR Washington, VT Shiawassee, M Shiawassee, M Shiawassee, M Hendricks, IN Loraine, OH Santa Barbara, CA Mahoning, OH
Facility Type Juniper Ridge Landfill Coventry Municipal Solid Waste Facility Liberty Landfill, Inc.
Waste Management, Inc Pine Tree Acres
Landfill Hoosier Energy Sarasota Landfill Gas-to-Energy Venice Park Recycling & Disposal Facility
City of San Diego, Public Utilities
Department Landfill
Columbia Ridge Landfill and Recycling
Center
Columbia Ridge Landfill and Recycling
Center Moretown Landfill Gas to Energy Facility Venice Park Landfill Venice Park Landfill Venice Park Landfill Twin Bridges Recycling and Disposal Facility Loraine County LFG Power Station City of Santa Maria Landfill
Carbon Limestone Landfill Gas Power
Station
Date of ATC
Date of PTO 3/30/2016 3/4/2016 10/22/2015 2/13/2015 12/23/2013 12/18/2013 12/11/2013 9/25/2013 6/21/2013 6/21/2013 7/12/2012 5/8/2012 5/8/2012 5/8/2012 3/5/2012 9/14/2011 8/25/2011 7/5/2011
Process Name Engines #1, #2, #3 Stationary Internal Combustion Engin Landfill Gas-Fired Engine Generator ICE Engines Engines Four landfill gas-to-energy engines 4 CAT engines using landfill gas ICE Landfill Gas Fired Engine Caterpillar 3516 Engine Caterpillar 3520C Engine Landfill gas to energy engines (2)Caterpillar 3516 Generator Engine Caterpillar 3512 Generator Engine Landfill Gas Generator Engine Caterpillar 3520 Generator Engines (2)Reciprocating Internal Combustion Engine Internal Combustion Engine Caterpillar engines (2)
Fuel Type Landfill Gas Landfill Gas Landfill Gas Landfill Gas Treated Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas
Throughput 16.5 MMBTU/HR 2535 SCFM 1.6 MW (2233 BHP) 541 SCFM 2.6 MW 554 SCFM (2242 BHP) 1600 KW 2233 BHP 1400 MMdscf/yr 2328 MMdscf/yr 1600 KW 800 KW (1148 HP) 615 KW (861 HP) 1600 KW (2233 HP) 1.6 MW (2233 HP) 2233 HP 1.426 MW (1966 HP) 2233 HP
Notes
Polluntants
NOX
Technology Air/Fuel Ratio Controllers Good combustion practices
Efficient combustion design and air-fuel
controllers Engine Design Electronic AFRC Electronic AFRC Electronic AFRC Lean burn technology Lean burn with AFRC Lean burn technology
Limit 0.6 g/bhp-hr
2.97 lb/hr 0.6 g/bhp-hr 0.6 g/hp-hr
0.6 g/bhp-hr
3 lb/hr 0.5 g/bhp-hr 1.45 g/bhp-hr
183.8 lb/mmdscf
0.6 g/hp-hr
2.954 lb/hr 2 g/bhp-hr 2 g/bhp-hr 0.6 g/bhp-hr
2.46 lb/hr
10.78 tons/yr
0.5 g/bhp-hr
38 ppmvd @ 15% 02 6 min
5.9 lb/hr both engines together
25.84 tons/yr both engines together
3 g/bhp-hr
CO
Technology Service/Cleaning Good combustion practices Proper combustion in engines Engine design and maintenance Electronic AFRC Electronic AFRC Electronic AFRC Good combustion practices Lean burn technology Lean burn with AFRC Lean burn technology
Limit 3.5 g/bhp-hr
17.3 lb/hr
3.5 g/bhp-hr
17.3 lb/hr 3.3 g/bhp-hr 2.5 g/hp-hr
3.5 g/bhp-hr
17.3 lb/hr
3.3 g/bhp-hr
16.3 lb/h
2.5 g/bhp-hr
285.9 lb/mmdscf
3.6 g/hp-hr
17.72 lb/hr
2.75 g/bhp-hr 3.1 g/bhp-hr 3.03 g/bhp-hr 3.3 g/bhp-hr 3.3 g/hp-h
13.53 lb/hr
59.26 tons/yr
2.75 g/bhp-hr
308 ppmvd @ 15% 02 6 min
1.64 lb/hr both engines together
7.18 tons/yr both engines together
1 g/bhp-hr
VOC
Technology Engine Design Lean burn with AFRC
Limit 0.71 g/hp-hr 0.63 g/bhp-hr 20 PPM @ 15% 02 5.4 lb/mmdscf
20 ppm @ 3% O2
23.5 lb/mmdscf
28.82 lb/hr
125.79 tons/yr 86 ppmvd @ 15% 02 6 min 28.82 lb/hr125.79 tons/yr
PM2.5 total PM total PM total PM
Technology Coalescing Filters Good combustion practices Proper O&M Proper O&M Proper O&M
Limit 1.2 lb/hr 23.3 lb/mmcf, CH4 dry 0.1 g/hp-hr
0.1 g/hp-hr
0.253 lb/hr
0.492 lb/hr
0.1 g/hp-hr 0.2 g/bhp-hr 0.2 g/bhp-hr 0.2 g/bhp-hr
PM10
Technology Coalescing Filters
Limit 1.2 lb/hr
0.49 lb/hr
2.15 tons/yr
0.1 g/bhp-hr
0.98 lb/hr both engines together
4.3 tons/yr both engines together
0.1 g/bhp-hr
SO2
Technology
Limit 3.51 lb/hr 300 ppm
49.91 lb/mmdscf
0.28 lb/hr
1.23 tons/yr
0.56 lb/hr both engines together
2.46 tons/yr both engines togethe
Hydrochloric Acid
Technology
Limit 0.36 lb/hr
1.58 tons/yr
0.3 lb/hr both engines together
1.32 tons/yr both engines togethe
Visible Emissions
Technology
Limit 10% opacity as a 6 min avg 10% opacity as a 6 min avg
Formaldehyde
Technology
Limit
Hydrogen Sulfide
Technology 300 ppm 98% DRE
0.53 lb/mmdscf
Limit
(1) - Tentatively identified compound
U - non-detect, value shown is the reporting limit.
76
J - estimated value, above the method detection limit, but below the reporting limit.
Table B-1. BACT Determination for Engines
USEPA RACT/BACT/LAER Clearinghouse for Category 17.140 - Internal Combustion Engines - Large (>500 HP) - Landfill/Digester/Bio-Gas
Use of contents on this sheet is subject to the limitations specified in this document
Tables for BACT doc.xlsx
Attachment B
Facility 1 Facility 2 Facility 3 Facility 4 Facility 5 Facility 6 Facility 7 Facility 8 Facility 9 Facility 10 Facility 11
Air District Maine DEP Vermont DEC Indiana DEM Michigan DEQ Illinois EPA Florida DEP Michigan DEQ San Diego County APCD Oregon DEQ Oregon DEQ Vermont DEC
County, State Penobscot, ME Orleans, VT White, IN Macomb, MI Ogle, IL Sarasota, FL Lennon, MI San Diego, CA Gilliam, OR Gilliam, OR Washington, VT
Facility Type Juniper Ridge Landfill Coventry Municipal Solid Waste Facility Liberty Landfill, Inc.
Waste Management, Inc Pine Tree Acres
Landfill Hoosier Energy Sarasota Landfill Gas-to-Energy Venice Park Recycling & Disposal Facility
City of San Diego, Public Utilities
Department Landfill
Columbia Ridge Landfill and Recycling
Center
Columbia Ridge Landfill and Recycling
Center Moretown Landfill Gas to Energy Facility
Date of ATC
Date of PTO 3/30/2016 3/4/2016 10/22/2015 2/13/2015 12/23/2013 12/18/2013 12/11/2013 9/25/2013 6/21/2013 6/21/2013 7/12/2012
Process Name Engines #1, #2, #3 Stationary Internal Combustion Engin Landfill Gas-Fired Engine Generator ICE Engines Engines Four landfill gas-to-energy engines 4 CAT engines using landfill gas ICE Landfill Gas Fired Engine Caterpillar 3516 Engine Caterpillar 3520C Engine Landfill gas to energy engines (2)
Fuel Type Landfill Gas Landfill Gas Landfill Gas Landfill Gas Treated Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas Landfill Gas
Throughput 16.5 MMBTU/HR 2535 SCFM 1.6 MW (2233 BHP) 541 SCFM 2.6 MW 554 SCFM (2242 BHP) 1600 KW 2233 BHP 1400 MMdscf/yr 2328 MMdscf/yr 1600 KW
Notes
Polluntants
NOX
Technology Air/Fuel Ratio Controllers Good combustion practices
Efficient combustion design and air-fuel
controllers Engine Design
Limit 0.6 g/bhp-hr
2.97 lb/hr 0.6 g/bhp-hr 0.6 g/hp-hr
0.6 g/bhp-hr
3 lb/hr 0.5 g/bhp-hr 1.45 g/bhp-hr
183.8 lb/mmdscf
0.6 g/hp-hr
2.954 lb/hr
CO
Technology Service/Cleaning Good combustion practices Proper combustion in engines Engine design and maintenance
Limit 3.5 g/bhp-hr
17.3 lb/hr
3.5 g/bhp-hr
17.3 lb/hr 3.3 g/bhp-hr 2.5 g/hp-hr
3.5 g/bhp-hr
17.3 lb/hr
3.3 g/bhp-hr
16.3 lb/h
2.5 g/bhp-hr
285.9 lb/mmdscf
3.6 g/hp-hr
17.72 lb/hr
2.75 g/bhp-hr
VOC
Technology Engine Design
Limit 0.71 g/hp-hr 0.63 g/bhp-hr 20 PPM @ 15% 02 5.4 lb/mmdscf
20 ppm @ 3% O2
23.5 lb/mmdscf
PM2.5 total PM total PM total PM
Technology Coalescing Filters Good combustion practices
Limit 1.2 lb/hr 23.3 lb/mmcf, CH4 dry 0.1 g/hp-hr
0.1 g/hp-hr
0.253 lb/hr
0.492 lb/hr
0.1 g/hp-hr
PM10
Technology Coalescing Filters
Limit 1.2 lb/hr
SO2
Technology
Limit 3.51 lb/hr 300 ppm
49.91 lb/mmdscf
Hydrochloric Acid
Technology
Limit
Visible Emissions
Technology
Limit
Formaldehyde
Technology
Limit
Hydrogen Sulfide
Technology 300 ppm 98% DRE
0.53 lb/mmdscf
Limit
(1) - Tentatively identified compound
U - non-detect, value shown is the reporting limit.
76
J - estimated value, above the method detection limit, but below the reporting limit.
Table B-1. BACT Determination for Engines
USEPA RACT/BACT/LAER Clearinghouse for Category 17.140 - Internal Combustion Engines - Large (>500 HP) - Landfill/Digester/Bio-Gas
Facility 19 Facility 20
Michigan DEQ Michigan DEQ
Wayne, MI Ottawa, MI
Carleton Farms Landfill Ottawa Generating Station
6/29/2011 6/17/2011
Landfill gas fired generator engines (2)Landfill gas fire generator engine
Landfill Gas Landfill Gas
260,880 mmBtu/yr combined for both
engines. Each engine greater than 500 HP 264.38 MMscf/yr (2233 HP)
Good combustion practices with AFRC Good combustion practices with AFRC
0.6 g/bhp-hr each engine 1 g/bhp-hr
Good combustion practices with AFRC Good combustion practices with AFRC
2.2 g/ghp-hr each engine 3.3 g/ghp-hr
Good combustion practices with AFRC
0.15 g/bhp-hr
Good combustion practices with AFRC
0.23 g/bhp-hr each engine
Good combustion practices with AFRC
1.25 lb/hr each engine
Use of contents on this sheet is subject to the limitations specified in this document
Tables for BACT doc.xlsx
Attachment B
Table B-2. BACT Determination for Engines
California Statewide Clearinghouse for Internal Combustion Engines: Landfill or Digester Gas Fired
Facility 1 Facility 2 Facility 3
Air District South Coast Santa Barbara County APCD Santa Barbara County APCD
County, State Orange, CA Santa Barbara, CA Santa Barbara, CA
Facility Type Orange County Sanitation District City of Santa Maria Landfill
City of Santa Maria Wastewater Treatment
Plant
Date of ATC 4/7/2010
Date of BACT Determination 4/4/2017
Date of PTO 8/26/2011
Process Name IC Engine Internal Combustion Engine V-12 gas-fired ICE
Fuel Type Digester Gas Landfill Gas Digester Gas
Throughput 3471 HP 1.426 MW (1966 HP) 510 BHP
Notes Cooper Bessmer MAN
Polluntants
NOX
Technology Oxidation Catalyst, SCR Lean burn with AFRC Air to Fuel Ratio, Regulation Compliance
Limit 11 ppmvd at 15% O2 38 ppmvd @ 15% O2 6 min 15 ppmvd at 15% O2
CO
Technology Oxidation Catalyst, SCR Lean burn with AFRC Air to Fuel Ratio, Regulation Compliance
Limit 250 ppmvd at 15% O2 Lean burn with AFRC 333 ppmvd at 15% O2
VOC
Technology Oxidation Catalyst, SCR Lean burn with AFRC
Limit 30 ppmvd at 15% O2 86 ppmvd @ 15% O2 6 min
PM2.5
Technology
Limit
PM10
Technology
Limit
SO2
Technology
Limit
Hydrochloric Acid
Technology
Limit
Visible Emissions
Technology
Limit
Formaldehyde
Technology
Limit
Hydrogen Sulfide
Technology
Limit
ROG
Technology
Limit
(1) - Tentatively identified compound
U - non-detect, value shown is the reporting limit.
J - estimated value, above the method detection limit, but below the reporting limit.
Use of contents on this sheet is subject to the limitations specified in this document
Tables for BACT doc.xlsx
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Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

C
Use of contents on this sheet is subject to the limitations specified at the beginning of this document.
BACT Determination for Cogen Engines 3 and 4 TM - FINAL.docx
Attachment C: Additional Controls Retrofit Cost Estimate

Technical Memorandum Best Available Control Technology Determination for Cogen Engines 3 and 4

C
Use of contents on this sheet is subject to the limitations specified at the beginning of this document.
BACT Determination for Cogen Engines 3 and 4 TM - FINAL.docx

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Central Valley Engine Exhaust SCR Retrofit Conceptual Cost Jim Schettler
2/1/2021
Equipment Item Size Cost, each $Remarks
Oxidization catalyst + SCR system For each engine 140,000 vendors quotes
Urea solution atomizing air compressor For this size SCR 6,000 complete
Urea solution atomizing air piping 60' per engine 1,440 approx.
Urea solution storage tank, 600 gallons HDPE 4,500 vendors quotes
Urea solution storage tank, fill and vent piping 3"3,450 HDPE
Urea solution fill pump as needed 7,500 gear pump
Replacing 20" SST piping with 24" SST 46' each engine 31,280 sch 10S
High temp exhaust piping insulation, 24" dia 2" thick, 50'7,200 approx.
24" SST piping supports lump sum 3,754
Expansion joints for 24" SST pipe 3 per engines 13,500 SST bellows
Urea solution piping, 1/2" SST 65' per engine 1,560
subtotal $220,184
SCR sensors & electric controls wiring and controls 17,615 8%
Electrical wiring, motor starters, conduit, and misc.35,229 16%
subtotal $273,028
Equipment installation, per "RS Means Guide"at 35%$95,560 estimating guide
Structural steel modifications to 2nd deck approx.65,000 retrofit
Structural steel modifications to 3rd deck approx.28,000 retrofit
Structural modifications to roof approx.23,400 retrofit
Structural mods to building wall for 24" EE dia approx.31,560 retrofit
subtotal $516,547
Engineering costs at 12%61,986 typical, retrofit
Contingency at 15%77,482
Total for each engine-generator $656,000 approximately
Table 1. Estimated Costs
As requested, here is a brief conceptualized cost estimate to add oxidation catalysts and SCR systems to the new 1812-kW Central
Valley Jenbacher engine-generators. The costs below are per engine.
Currently each 1812-kW Jenbacher engines is now installed in the Power Gen Building that was originally built in 1984 and was designed
for housing five 625-kW engine generators. Over the years the original rich-burn Waukesha engines were converted to lean-burn engines
and upgraded, or replaced with 1300-kW lean-burn engine-generators. More recently the original engines were replaced with current
technology lean-burn Jenbacher engines (engines 1 & 2) that were located with the spaces vacated by removing the original machines.
When the needed engine exhaust heat recovery heat exchangers and silencers were added, on the now larger diameter 20" diameter
exhaust piping, there was little available physical space remaining. Additionally the replacement lean-burn engines (engines 3 & 4), just
like all large IC engines, have limitations on their allowed exhaust backpressure, now totaling 20-inches water column (inches WC), per
their manufacturer.
As before, the new Jenbacher engine generators (engines 1 & 2) and their support exhaust equipment are located within the existing
building, for noise containment and climate control. Based on the reconfigured 1812-kW engine-generators, we now have two serious
limitations on adding more exhaust equipment such as the proposed oxidation catalysts and the SCR related equipment.
1. The longest available section of straight bare exhaust piping is now about 9 feet long. Oxidation catalyst, the SCR mixing section
and their SCR catalyst are much longer, totaling 15 feet per one candidate supplier's quote, and 16 feet long per another quote.
2. Even with the now larger size 20" diameter engine exhaust piping, when totaling all the backpressure imposed by the exhaust
piping and the needed exhaust heat recovery equipment, the remaining allowable backpressure is only about 3" WC, out of the total
allowable 20" WC. Quotations from 2 experienced oxidation catalysts and SCR suppliers state that their exhaust treatment
equipment will need ether 8" WC or 10" WC backpressure, or much more pressure than available. This suggests that larger
diameter 24" dia EE will likely be needed, in lieu of 20" dia.
The estimated cost of the oxidation catalyst and SCR equipment, plus needed building modifications and equipment is shown below in
Table 1:
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Reasonably Available Control Technology Analysis for NOx

B
1_RACT Analysis
Attachment B: 2023 BACT - Emergency Engines
Technical Memorandum

Limitations:
This document was prepared solely for Central Valley Water Reclamation Facility (CVWRF) in accordance with professional standards at the time the
services were performed and in accordance with the contract between CVWRF and Brown and Caldwell dated January 3, 2023. This document is
governed by the specific scope of work authorized by CVWRF; it is not intended to be relied upon by any other party except for regulatory authorities
contemplated by the scope of work. We have relied on information or instructions provided by CVWRF and other parties and, unless otherwise
expressly indicated, have made no independent investigation as to the validity, completeness, or accuracy of such information.
.202 Cousteau Place, Suite 175
Davis, CA 95618

T: 530.747.0650

Prepared for: Central Valley Water Reclamation Facility
Project Title: Emergency Diesel Engine Generators Serving Blower Building
Project No.: 159388
Technical Memorandum
Subject: BACT Analysis for Emergency Engine Generators 9, 10, and 11
Date: June 26, 2023
To: Bryan Mansell, Chief Engineer
From: Jason Wiser
Copy to: File

Prepared by:
Jennifer Border, Principal Engineer

Reviewed by:
Don Trueblood, Chief Scientist

Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
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BACT Emerg Engines 9, 10, 11.docx
Table of Contents
Section 1: Background..............................................................................................................................................1
1.1 Site History and Permitting Timeline..................................................................................................................1
1.2 Attainment Status................................................................................................................................................1
1.3 Standby Emergency Diesel Engine Generators.................................................................................................2
1.3.1 Engine Emissions and Controls..........................................................................................................2
Section 2: Best Available Control Technology Analysis...........................................................................................3
2.1 Pollutants for Which BACT is Required..............................................................................................................4
2.2 Control Technologies...........................................................................................................................................4
Section 3: Conclusion................................................................................................................................................5
Attachment A: Emergency Engine Data....................................................................................................................A
Attachment B: EPA RBLC Search Results ................................................................................................................B
List of Tables
Table 1. Engine Data .................................................................................................................................................2
Table 2. RBLC BACT Methods of Control..................................................................................................................4
Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
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BACT Emerg Engines 9, 10, 11.docx
Section 1: Background
The Central Valley Water Reclamation Facility (CVWRF) is located at 800 West Central Valley Road in Salt
Lake City, Salt Lake County, Utah. CVWRF treats wastewater using a combination of processes. Every day,
between 50 and 60 million gallons of wastewater are conveyed into the facility for treatment. Those millions
of gallons of water are processed, impurities are separated and treated, and harmful bacteria, protozoa, and
viruses are eliminated so that only clean water is returned to Mill Creek and the Jordan River.
1.1 Site History and Permitting Timeline
CVWRF is currently permitted under Title V Air Permit 3500191001, issued March 16, 2020, through the
State of Utah, Department of Environmental Quality, Division of Air Quality (DAQ). Emissions at the facility are
primarily associated with electric power generation from the operation of prime-use digester gas/natural
gas-fueled engine generators and standby emergency diesel engine generators.
The facility is currently undergoing construction of a Biological Nutrient Removal (BNR) system to reduce
effluent total phosphorus concentrations as required by the Technology Based Phosphorus Effluent Limit
Rule promulgated by the Utah DWQ in 2015. The new standby emergency diesel engine generators
(hereafter referred to as “engines”) will provide emergency power to the blower building which serves the
BNR system. The generators are on-site but are not commissioned; commissioning is expected to take place
in late 2023.
1.2 Attainment Status
CVWRF is located in Salt Lake County, Utah which is currently designated non-attainment for PM2.5, SO2 and
Ozone; the area is also designated as a PM10 maintenance area. Salt Lake County was designated as
marginal non-attainment for Ozone on June 4, 2018. Since the area was not able to attain the ozone
standard within the three-year period allowed by United States Environmental Protection Agency (USEPA),
the area was re-designated as moderate non-attainment for ozone on November 7, 2022.
Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
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1.3 Standby Emergency Diesel Engine Generators
Table 1 provides information regarding each of the three identical engines.
Table 1. Engine Data
Manufacturer MTU Rolls Royce
Generator Model 641-VL75-M
Engine Model 16V4000G74S
Displacement 76.3 liters
Number of Cylinders 16
Displacement per cylinder 4.77 liters per cylinder
Generator Power (Electrical)2,000 kW
Engine Power (estimated)2,884 BHP`
Engine Emissions Data:
Certification
NOx + NMHC
CO
PM
Tier II
5.38 g/hp-hr
0.45 g/hp-hr
0.04 g/hp-hr
a. Engine horsepower based on the fuel consumption provided in the manufacturer spec sheet at 100% load
and assumptions from footnotes “a” and “e” of AP-42 Table 3.4 1
CO = Carbon Monoxide
kW = kilowatt(s)
g = gram(s)
hp-hr = horse power per hour
NMHC = Non-methane hydrocarbon
NOx = Nitrogen Oxides
PM = Particulate Matter
1.3.1 Engine Emissions and Controls
Since the engines do not drive fire pumps, were manufactured after 2006, and are being installed after July
11, 2005, they are subject to 40 Code of Federal Regulations (CFR) 60, Subpart IIII, Standards of
Performance for New Stationary Engines [40 CFR 60.4200]. Since the engines are designated for
emergency use, the model year is later than 2006, and the displacement is less than 30 liters per cylinder,
they are subject to the emissions standards provided in 40 CFR 60.4202 [40 CFR 60.4205]. Section 4202
of Subpart IIII further requires that engines rated at 50 HP or more must meet the emissions standards in 40
CFR 1039, Appendix I and the smoke standards in 40 CFR 1039.105. [40 CFR 60.4202(a)]. The emissions
standards in 40 CFR 1039, Appendix I for engines over 560 kW are equal to the emissions standards for
Tier 2 engines.
The section regarding smoke standards, 40 CFR 1039.105, states that the smoke opacity standards
provided do not apply to engines certified to a PM emission standard of 0.07 g/kW-hr (0.05 g/hp-hr) or
lower. Since the engines are certified to a PM emission standard of 0.04 g/hp-hr, the smoke opacity
standards do not apply.
Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
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BACT Emerg Engines 9, 10, 11.docx
CVWRF will be required to comply with the other provisions of Subpart IIII, specifically to:
Operate and maintain the engines according to the manufacturer’s emission-related written instructions;
Change only those emission-related settings that are permitted by the manufacturer;
Install and configure the engine according to the manufacturer’s emission-related specifications;
Limit operation of the engines for non-emergency purposes to a maximum of 100 hours per year (of
which up to 50 hours per year can be for uses not associated with maintenance and testing of the
engines).
The USEPA Certificate of Conformity for the engine family states that the following treatment devices are
integral to the engine (“non-after treatment devices”): electronic control and puff limiter. In addition, the
emissions guarantee provided by the manufacturer exceeds the emissions requirements of 40 CFR 1039,
Appendix I (the emissions standards are less than the Tier 2 emissions limits).
Section 2: Best Available Control Technology Analysis
Following USEPA Guidance, best available control technology (BACT) can be defined as the most stringent of
the following:
The lowest emission rate or most effective emission limitation successfully achieved in practice by the
same type of equipment, operated under similar conditions (rating and capacity), at the same type of
source; or
The lowest emission rate or most effective emission control device determined to be technologically
feasible and cost effective for the equipment being installed; or
The requirements of a State or Federal Performance Standard Regulation.
A BACT analysis is performed on a case-by-case basis and must consider emission rates and/or control
technologies that have been achieved on similar equipment or that are technologically feasible and cost
effective. These requirements have led to development of a standard procedure for case-by-case “top down”
BACT analyses.
Step 1: Identify pollutants for which BACT is required. Utah Department of Environmental Quality (DEQ)
regulations require BACT for all criteria pollutants.
Step 2: Identify emission rates and/or control technologies. Once the pollutants for which the BACT
analysis is required are identified, candidate emission rates and/or control technologies must be
identified.
Step 3: Evaluate technological feasibility of the emission rates and/or control technologies identified in
Step 2. Any emission rates and/or control technologies that are not technologically feasible should be
eliminated at this step.
Step 4: Rank remaining emission rates and/or control technologies by effectiveness. This ranking
should consider, as appropriate, control efficiency, resulting emission rates, energy impacts (fuel use,
etc.), and environmental impacts (secondary air emissions, hazardous waste production, impacts to
other media, etc.).
Step 5: Evaluate cost effectiveness of the most stringent emission rates and/or most effective controls.
Step 6: Select BACT.
Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
4
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BACT Emerg Engines 9, 10, 11.docx
2.1 Pollutants for Which BACT is Required
This BACT analysis considered emissions of NOx, CO, VOC, PM10, PM2.5, and SO2.
2.2 Control Technologies
Existing sources of information were used to identify emission controls that have been used for similar
projects. The Utah DEQ’s website contains several source-specific BACT analyses that were submitted by
facilities which are major sources of PM2.5 and PM2.5 precursors regarding various types of facilities.
Several of these documents contain an analysis of BACT measures for PM2.5 control from emergency
engines. BC reviewed these analyses and did not find any that provided achieved-in-practice controls that
exceed the PM-related controls already proposed for the engines.
In addition, in response to the area around the facility having been recently designated non-attainment for
ozone, the Utah DEQ website contains area source rules which apply to several specific source categories;
none of the rules apply directly or indirectly to internal combustion engines.
BC conducted an initial BACT determinations search of the following database:
USEPA Reasonable Available Control Technology (RACT)/BACT/Lowest Achievable Emission Rate
Clearinghouse (RBLC) – Category 17.110 – Internal Combustion Engines – Large (>500 hp) – Fuel Oil
(kerosene, aviation, and diesel) with a keyword search for “emergency”
The results from the RBLC initially provided over 6,000 potential determinations. However, the results were
further refined through filtering the information as follows:
Engines fired on fuel other than diesel were removed
Engines driving fire pumps were removed
Smaller engines (roughly under 1,000 hp) were removed
Pollutants were limited to criteria pollutants only and omitted carbon dioxide, hydrogen sulfide, and
visible emissions
The refined RBLC results provided 18 BACT determinations. The remaining control technologies cited are
listed in the Table 2 below.
Table 2. RBLC BACT Methods of Control
Pollutant Methods of Control
Particulate Matter
Minimize hours of operation
Tier II Engine
Good combustion practices
SOx Low sulfur fuel (15 ppm sulfur content)
VOC Minimize hours of operation
Tier II Engine
CO Minimize hours of operation
Tier II Engine
NOx 3.95 g/HP-hr – 4.46 g/HP-hra
a. BC requested verification from the agency which submitted the determination for the NOx
emission limit (PA 0291) and received a response from the Pennsylvania Department of
Environmental Protection stating that the source had never been constructed. Therefore,
this emissions limit was not demonstrated as achieved in practice and was not brought
forward for consideration as BACT.
Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
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BACT Emerg Engines 9, 10, 11.docx
As noted in the footnote for the NOx emission standard in Table 2 above, according to an email from the
Pennsylvania Department of Environmental Protection, the facility subject to the NOx emission limit was
never constructed and the limit was not achieved in practice. Therefore, this BACT determination was not
brought forward.
The remaining Methods of Control cited in the results from the RBLC search will be incorporated by CVWRF
in the operation of the emergency engines.
Section 3: Conclusion
In conclusion, CVWRF purchased MTU emergency engines 9, 10, and 11 and has installed them at the
facility. The engines are not currently operational as the facility which they will serve has not been
constructed yet.
The engines are considered to meet current BACT requirements for the size and type of operation with the
following provisions:
The engines are certified Tier II.
The engines will be operated and maintained according to the manufacturer's emission-related written
instructions;
Only those emission-related settings that are permitted by the manufacturer will be changed;
The engines will be installed and configured according to the manufacturer’s emission-related
specifications;
Operation of the engines for non-emergency purposes will be limited to a maximum of 100 hours per
year (of which up to 50 hours per year can be for uses not associated with maintenance and testing of
the engines).
Only ultra-low sulfur diesel fuel will be used in the engines.
The above provision are considered to satisfy the requirement that good combustion practices are utilized
during the operation of the engines.
Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
A
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BACT Emerg Engines 9, 10, 11.docx
Attachment A: Emergency Engine Data
Central Valley Water
Reclamation Facility
South Salt Lake, UT
(3) 2000kW Diesel Generators
JULY 2021
REV-2
Submitted by:
Nick Paolo
Smith Power Products,
Inc.
303-810-1085
[e-mail] SU
B
M
I
T
T
A
L
L
Date: September 14, 2020
Reference: SPP2702.4 CVWRF 3 Salt Lake City - 2000kW QTY 3 4160V
We are pleased to offer the following quote for the above project:
The proposal is per one-line drawing and specifications with clarifications in the notes section of the bill of
materials listed after the quote: please reference previous quote 2702.1
QUANTITY EQUIPMENT DESCRIPTION PRICE EACH TOTAL PRICE
3 MTU 2000kW Generator Set
M/N DS2000
Diesel Fuel
Derate: 2000kW @ 4300 Feet, 104°F
4160V Volt, 3 Phase, 60 HZ, 1800 RPM
Genset OPU Dry Assembly Weight: lbs.
Included Included
3 Generator Enclosure Weather Proof Level 2
85 dBA at 23’
Included Included
3 NGR’s Included Included
*Crane/rigging not included. Fuel not included.
Cat walks not included. If required, we can
provide an adder.
Equipment Description:
Generator:
Application Emergency Standby (3D) 1,
Frequency 60 Hz 1,
Generator Voltage 4160 V 1,
Phase 3 Phase 1,
Unit Specification Standard Unit 1,
Engine Model 16V4000G74S (24volts) 1,
Exhaust Emissions (EPA) EPA Tier 2 1,
Radiator Design Temperature 43°C 1,
Temp Rise 130° 1,
Power Output 2000 kW 1,
Full Load Amps 346 1,
Generator Frame and Wire Qty LSA 641-VL75-M (6 Wire) 1,
Generator Wire Configuration Wye 1,
Custom Generator Enclosure Sound 85dB(A) @ 23ft 1,
Fuel Tank UL142 24hr tank 1,
Control panel With Control Panel 1,
Circuit Breaker Options Exterior mounted 1,
Breaker Wire Color Scheme Standard Breaker Wire Color Scheme 1,
Paralleling Paralleling without MTU Components 1,
Central Valley Water Reclation Facility SEPT2020 REV0 Page 29 of 146
3
3
3 NGR’s
y
Generator Enclosure
MTU 2000kW Generator Set
M/N DS2000
2000kW @ 4300 Feet,104°F
4160 V
2000 kW
y
Sound 85dB(A) @ 23ft
UL142 24hr tank
()@
MTU 16V4000 DS2000 45 °C
Diesel Generator Set
2,000 kWe/60 Hz/Standby/380 - 13,800V
Voltage (L-L)380V † ‡416V † ‡440V † ‡480V † ‡600V ‡
Phase33333
PF 0.8 0.8 0.8 0.8 0.8
Hz 60 60 60 60 60
kW 2,000 2,000 2,000 2,000 2,000
kVA 2,500 2,500 2,500 2,500 2,500
Amps 3,798 3,470 3,280 3,007 2,406
skVA@30%
voltage dip 6,899 6,030 6,745 4,914 4,575
Generator model*841-M70-M 841-M70-M 841-M70-M 641-VL90-M 641-VL85-M
Q|œ¬
ҋ³|130 °C/40 °C 130 °C/40 °C 130 °C/40 °C 130 °C/40 °C 130 °C/40 °C
¢|t֋¢6 LEAD WYE 6 LEAD WYE 6 LEAD WYE 6 LEAD WYE 6 LEAD WYE
Voltage (L-L)4,160V 12,470V 13,200V 13,800V
Phase3333
PF 0.8 0.8 0.8 0.8
Hz 60 60 60 60
kW 2,000 2,000 2,000 2,000
kVA 2,500 2,500 2,500 2,500
Amps 347 116 109 105
skVA@30%
voltage dip 4,303 3,243 3,633 3,971
Generator model*641-VL75-M 4P6.6-2600-M 4P6.6-2600-M 4P6.6-2600-M
Q|œ¬
ҋ³|130 °C/40 °C 130 °C/40 °C 130 °C/40 °C 130 °C/40 °C
¢|t֋¢6 LEAD WYE 6 LEAD WYE 6 LEAD WYE 6 LEAD WYE

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Central Valley Water Reclation Facility SEPT2020 REV0 Page 50 of 146
MTU 16V4000 DS2000 45 °C
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Central Valley Water Reclation Facility SEPT2020 REV0 Page 53 of 146
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
2020 MODEL YEAR
CERTIFICATE OF CONFORMITY
WITH THE CLEAN AIR ACT
OFFICE OF TRANSPORTATION
AND AIR QUALITY
ANN ARBOR, MICHIGAN 48105
Certificate Issued To: MTU America, Inc.
(U.S. Manufacturer or Importer)
Certificate Number: LMDDL95.4GTZ-007
Effective Date:
01/29/2020
Expiration Date:
12/31/2020
_________________________
Byron J. Bunker, Division Director
Compliance Division
Issue Date:
01/29/2020
Revision Date:
N/A
Model Year: 2020
Manufacturer Type: Original Engine Manufacturer
Engine Family: LMDDL95.4GTZ
Mobile/Stationary Indicator: Stationary
Emissions Power Category: 560<kW<=2237
Fuel Type: Diesel
After Treatment Devices: No After Treatment Devices Installed
Non-after Treatment Devices: Electronic Control, Smoke Puff Limiter
Pursuant to Section 111 and Section 213 of the Clean Air Act (42 U.S.C. sections 7411 and 7547) and 40 CFR Part 60, and subject to the terms and conditions prescribed in those provisions, this certificate of
conformity is hereby issued with respect to the test engines which have been found to conform to applicable requirements and which represent the following engines, by engine family, more fully described in
the documentation required by 40 CFR Part 60 and produced in the stated model year.
This certificate of conformity covers only those new compression-ignition engines which conform in all material respects to the design specifications that applied to those engines described in the
documentation required by 40 CFR Part 60 and which are produced during the model year stated on this certificate of the said manufacturer, as defined in 40 CFR Part 60.
It is a term of this certificate that the manufacturer shall consent to all inspections described in 40 CFR 1068 and authorized in a warrant or court order. Failure to comply with the requirements of such a
warrant or court order may lead to revocation or suspension of this certificate for reasons specified in 40 CFR Part 60. It is also a term of this certificate that this certificate may be revoked or suspended or
rendered void ab initio for other reasons specified in 40 CFR Part 60.
This certificate does not cover engines sold, offered for sale, or introduced, or delivered for introduction, into commerce in the U.S. prior to the effective date of the certificate.
The actual engine power may lie outside the limits of the Emissions Power Category shown above. See the certificate application for details.
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Issued to: MTU America Inc
100 Power Dr
Mankato MN 56001-4790

This certificate confirms that
representative samples of
ENGINE GENERATORS
Stationary engine generator assemblies, Diesel Fueled, for
indoor use, Models 12V4000, 16V4000, 20V4000 followed
by D, followed by S, followed by 1250 thru 3250.

Have been investigated by UL in accordance with the
Standard(s) indicated on this Certificate.

Standard(s) for Safety: UL 2200-Engine Generators
CAN/CSA C22.2 No. 100-14-Motors and Generators
Additional Information: See the UL Online Certifications Directory at
https://iq.ulprospector.com for additional information.

This Certificate of Compliance does not provide authorization to apply the UL Mark. Only the UL Follow-Up
Services Procedure provides authorization to apply the UL Mark.

Only those products bearing the UL Mark should be considered as being UL Certified and covered under UL’s
Follow-Up Services.

Look for the UL Certification Mark on the product.

Central Valley Water Reclation Facility SEPT2020 REV0 Page 43 of 146

Accredited Body: DQS GmbH, August-Schanz-Straße 21, 60433 Frankfurt am Main, Germany

CERTIFICATE
This is to certify that

MTU America Inc.

100 Power Drive
Mankato, MN 56001
United States of America
has implemented and maintains a Quality Management System.
Scope:
Development, production, sales and service of decentralized energy systems.
Through an audit, documented in a report, it was verified that the management system
fulfills the requirements of the following standard:

ISO 9001 : 2015

Certificate registration no.
Excerpt from certificate registration no.
Valid from
Valid until
Date of certification
500767 QM15
353331 QM15
2018-08-15
2021-08-14
2018-08-15
DQS GmbH

Stefan Heinloth
Managing Director

Central Valley Water Reclation Facility SEPT2020 REV0 Page 44 of 146
Best Available Control Technology Analysis for Emergency Engine Generators 9, 10, and 11
B
Use of contents on this sheet is subject to the limitations specified at the beginning of this document.
BACT Emerg Engines 9, 10, 11.docx
Attachment B: EPA RBLC Search Results
USEPA RBLC Output
Page 1 of 2
Exported on June 15, 2023
Filtered on Fuel (Diesel)
Excludes:
fire pumps
smaller engines
RBLCID Facility Name
Corporate Or
Company Name
Facility
County
Facility
State
EPA
Region Other Agency Contact Info Permit Num SIC Code NAICS Code
Complete
Application
Date
Permit
Issuance
Date
Date Determination
Last Updated
Permit
Type Process Name Primary Fuel Throughput Tput Unit Pollutant Test Method
Control Method
Description
Emission
Limit
Emission Limit
1 Unit
Case-By-Case
Basis
TX-0728
PEONY CHEMICAL
MANUFACTURING
FACILITY BASF BRAZORIA TX 6
David Infortunio
512-239-1247
<[e-mail]
v>118239, N200 2813 325311 2/11/2015 4/1/2015 1/31/2020 B
Emergency
Diesel
Generator Diesel 1500 hp
Carbon
Monoxide Unspecified
Minimized hours
of operations Tier
II engine 0.0126 G/HP HR
OTHER CASE-
BY-CASE
MA-0039
SALEM HARBOR
STATION
REDEVELOPMENT
FOOTPRINT POWER
SALEM HARBOR
DEVELOPMENT LP ESSEX MA 1
Cosmo Buttaro
MassDEP Northeast Regional
Office
205B Lowell Street
Wilmington, MA 01887
[phone]
[e-mail] NE-12-022 4911 221112 9/9/2013 1/30/2014 5/5/2016 A
Emergency
Engine/Generat
or ULSD 7.4 MMBTU/H
Carbon
Monoxide Unspecified 2.6 GM/BHP-H
OTHER CASE-
BY-CASE
PA-0291
HICKORY RUN ENERGY
STATION
HICKORY RUN
ENERGY LLC LAWRENCE PA 3
JOHN F. GUTH
NORTHWEST REGION AIR
PROGRAM MANAGER
230 Chestnut Street
Meadville, PA 16335-3481
814-332-6940 37-337A 4911 221112 12/20/2012 4/23/2013 3/2/2020 A
EMERGENCY
GENERATOR
Ultra Low
sulfur
Distillate 7.8 MMBTU/H
Carbon
Monoxide Unspecified 5.79 LB/H
OTHER CASE-
BY-CASE
*PA-0313
FIRST QUALITY TISSUE
LOCK HAVEN PLT
FIRST QUALITY
TISSUE, LLC CLINTON PA 3 18-00030C 2676 322291 4/14/2015 7/27/2017 3/26/2019 B
Emergency
Generator Diesel 2500 bhp
Carbon
Monoxide Unspecified 3.5 G
PA-0291
HICKORY RUN ENERGY
STATION
HICKORY RUN
ENERGY LLC LAWRENCE PA 3
JOHN F. GUTH
NORTHWEST REGION AIR
PROGRAM MANAGER
230 Chestnut Street
Meadville, PA 16335-3481
814-332-6940 37-337A 4911 221112 12/20/2012 4/23/2013 3/2/2020 A
EMERGENCY
GENERATOR
Ultra Low
sulfur
Distillate 7.8 MMBTU/H
Nitrogen
Oxides (NOx)Unspecified 9.89 LB/H
OTHER CASE-
BY-CASE
TX-0728
PEONY CHEMICAL
MANUFACTURING
FACILITY BASF BRAZORIA TX 6
David Infortunio
512-239-1247
<[e-mail]
v>118239, N200 2813 325311 2/11/2015 4/1/2015 1/31/2020 B
Emergency
Diesel
Generator Diesel 1500 hp
Particulate
matter,
filterable 10µ
(FPM10)Unspecified
Minimized hours
of operations Tier
II engine 0.15 LB/H
OTHER CASE-
BY-CASE
TX-0728
PEONY CHEMICAL
MANUFACTURING
FACILITY BASF BRAZORIA TX 6
David Infortunio
512-239-1247
<[e-mail]
v>118239, N200 2813 325311 2/11/2015 4/1/2015 1/31/2020 B
Emergency
Diesel
Generator Diesel 1500 hp
Particulate
matter,
filterable 2.5µ
(FPM2.5)Unspecified
Minimized hours
of operations Tier
II engine 0.15 LB/H
OTHER CASE-
BY-CASE
MI-0447
LBWL--ERICKSON
STATION
LANSING BOARD OF
WATER AND LIGHT EATON MI 5
Please contact the permit
engineer
Melissa Byrnes
517-648-6339
[e-mail] 74-18A 4911 221112 9/22/2020 1/7/2021 9/10/2021 D
EUEMGD--
emergency
engine diesel fuel 4474.2 KW
Particulate
matter,
filterable
(FPM)Unspecified
Good combustion
practices, burn
ultra-low diesel
fuel, and will be
NSPS compliant.0.2 G/KW-H
OTHER CASE-
BY-CASE
TX-0728
PEONY CHEMICAL
MANUFACTURING
FACILITY BASF BRAZORIA TX 6
David Infortunio
512-239-1247
<[e-mail]
v>118239, N200 2813 325311 2/11/2015 4/1/2015 1/31/2020 B
Emergency
Diesel
Generator Diesel 1500 hp
Particulate
matter,
filterable
(FPM)Unspecified
Minimized hours
of operations Tier
II engine 0.15 LB/H
OTHER CASE-
BY-CASE
PA-0291
HICKORY RUN ENERGY
STATION
HICKORY RUN
ENERGY LLC LAWRENCE PA 3
JOHN F. GUTH
NORTHWEST REGION AIR
PROGRAM MANAGER
230 Chestnut Street
Meadville, PA 16335-3481
814-332-6940 37-337A 4911 221112 12/20/2012 4/23/2013 3/2/2020 A
EMERGENCY
GENERATOR
Ultra Low
sulfur
Distillate 7.8 MMBTU/H
Particulate
matter, total
(TPM)Unspecified 0.02 TPY
OTHER CASE-
BY-CASE
USEPA RBLC Output
Page 2 of 2
*PA-0313
FIRST QUALITY TISSUE
LOCK HAVEN PLT
FIRST QUALITY
TISSUE, LLC CLINTON PA 3 18-00030C 2676 322291 4/14/2015 7/27/2017 3/26/2019 B
Emergency
Generator Diesel 2500 bhp
Particulate
matter, total
(TPM)Unspecified 0.2 G
TX-0728
PEONY CHEMICAL
MANUFACTURING
FACILITY BASF BRAZORIA TX 6
David Infortunio
512-239-1247
<[e-mail]
v>118239, N200 2813 325311 2/11/2015 4/1/2015 1/31/2020 B
Emergency
Diesel
Generator Diesel 1500 hp
Sulfur Dioxide
(SO2)Unspecified
Low sulfur fuel 15
ppmw 0.61 LB/H
OTHER CASE-
BY-CASE
MA-0039
SALEM HARBOR
STATION
REDEVELOPMENT
FOOTPRINT POWER
SALEM HARBOR
DEVELOPMENT LP ESSEX MA 1
Cosmo Buttaro
MassDEP Northeast Regional
Office
205B Lowell Street
Wilmington, MA 01887
[phone]
[e-mail] NE-12-022 4911 221112 9/9/2013 1/30/2014 5/5/2016 A
Emergency
Engine/Generat
or ULSD 7.4 MMBTU/H
Sulfur Dioxide
(SO2)Unspecified 0.011 LB/H
OTHER CASE-
BY-CASE
OH-0352
OREGON CLEAN ENERGY
CENTER ARCADIS, US, INC.LUCAS OH 5 P0110840 4931 221112 4/3/2013 6/18/2013 5/4/2016 A
Emergency
generator diesel 2250 KW
Sulfur Dioxide
(SO2)
EPA/OAR Mthd
6C 0.03 LB/H N/A
PA-0291
HICKORY RUN ENERGY
STATION
HICKORY RUN
ENERGY LLC LAWRENCE PA 3
JOHN F. GUTH
NORTHWEST REGION AIR
PROGRAM MANAGER
230 Chestnut Street
Meadville, PA 16335-3481
814-332-6940 37-337A 4911 221112 12/20/2012 4/23/2013 3/2/2020 A
EMERGENCY
GENERATOR
Ultra Low
sulfur
Distillate 7.8 MMBTU/H
Sulfur Oxides
(SOx)Unspecified 0.01 LB/H
OTHER CASE-
BY-CASE
TX-0728
PEONY CHEMICAL
MANUFACTURING
FACILITY BASF BRAZORIA TX 6
David Infortunio
512-239-1247
<[e-mail]
v>118239, N200 2813 325311 2/11/2015 4/1/2015 1/31/2020 B
Emergency
Diesel
Generator Diesel 1500 hp
Volatile
Organic
Compounds
(VOC)Unspecified
Minimized hours
of operations Tier
II engine 0.7 LB/H
OTHER CASE-
BY-CASE
PA-0291
HICKORY RUN ENERGY
STATION
HICKORY RUN
ENERGY LLC LAWRENCE PA 3
JOHN F. GUTH
NORTHWEST REGION AIR
PROGRAM MANAGER
230 Chestnut Street
Meadville, PA 16335-3481
814-332-6940 37-337A 4911 221112 12/20/2012 4/23/2013 3/2/2020 A
EMERGENCY
GENERATOR
Ultra Low
sulfur
Distillate 7.8 MMBTU/H
Volatile
Organic
Compounds
(VOC)Unspecified 0.7 LB/H
OTHER CASE-
BY-CASE
*PA-0313
FIRST QUALITY TISSUE
LOCK HAVEN PLT
FIRST QUALITY
TISSUE, LLC CLINTON PA 3 18-00030C 2676 322291 4/14/2015 7/27/2017 3/26/2019 B
Emergency
Generator Diesel 2500 bhp
Volatile
Organic
Compounds
(VOC)Unspecified 3.5 G
RBLCID Facility Name
Corporate Or
Company Name
Facility
County
Facility
State
EPA
Region Other Agency Contact Info Permit Num SIC Code NAICS Code
Complete
Application
Date
Permit
Issuance
Date
Date Determination
Last Updated
Permit
Type Process Name Primary Fuel Throughput Tput Unit Pollutant Test Method
Control Method
Description
Emission
Limit
Emission Limit
1 Unit
Case-By-Case
Basis
Reasonably Available Control Technology Analysis for NOx

C
1_RACT Analysis

Attachment C: Flare Replacement Cost Estimate

Construction Cost
$1,042,698 recent proposal for an enclosed flare to be located in Washington
560 scfm - proposed gas flowrate to be handled by flare
68 scfm - current gas flow to flare at CVWRF
$294,273 Estimated construction cost for flare to handle current gas flow^
^ using the "Rule of six tenths" for cost estimation
NOx Emissions from flare 0.52 tons/year
NOx Emissions from enclosed flare 0.46 tons/year
NOx reduction 0.06 tons/year
Capital Cost $294,273
Life of Enclosed Flare 20 years
8.50%Prime Rate (10/17/2023)
Present Value Control Cost:$31,096
Annual Maintenance Cost:$3,007
Lifetime Maintenance Costs $60,145
Annualized Cost of Control:$568,390 per ton NOx removed
Emissions Reduction
0.068 lb NOx/mmbtu open flare emissions factor (AP-42, Table 13.5-1)
0.06 lb NOx/mmbtu enclosed flare emissions factor (manufacturer guarantees)
12%NOx reduction
Enclosed Flare Operating Cost 11/7/2023 9:31 Jim Schettler
Energy Cost Used (input values, typical)
Natural Gas $3.50 per million Btu
Electricity $0.086 per kWhr, average
Flare Energy Use per John Zink rep, Bob Erdman [phone]
Natural gas not required for the pilot light, nor the flare itself
Electric Power Usage
Blower 10 HP 8.29 kW 100 Hr/yr (testing)assumed
828.56 kWhr/year
$71.26 per year
Control Panel (heater)watts 125 Varec flare Catalog
condensation control, typical 2,000 hours per year assumed
250 kWhr/yr
Heat tracer watts 800 estimate flame arrester and flame check
Heat tracer watts 500 estimate drip trap
Heat tracer watts 200 estimate PRV actuator
kW total 1.5
hours per year 500 freeze protection assumed
kWhr/yr 750
Electric heating 1000 kWhr/year
Electric heating $86.00
total per year, electric usage cost $157 for motors, freeze protection, condensation control
Replacement Equipment Item Costs
Thermocouples every other year $1,000 see above approximate replacement
PLC every 5 years $3,000 see above
Typical 10 year cost
Thermocouples replace 5 $5,000 per Bob Erdman
PLCs replace 2 $6,000 per Bob Erdman
Typical 10 year cost, total $11,000
Source Testing Cost
typical test cost $2500 per source test per Bob Erdman
first year $2,500 initial source test
first year $2,500 added testing and adjustments
2nd year $2,500 yearly source test
3rd year $0 source test every other year, after 2 years
4th year $2,500 source test
5th year $0 source test every other year, after 2 years
6th year $2,500 source test
7th year $0 test every other year
8th year $2,500 source test
9th year $0 test every other year
10th year $2,500 source test
10 year total $17,500 per a source test every other year
Total operating cost per year, average $3,007
Reasonably Available Control Technology Analysis for NOx

D
1_RACT Analysis
Attachment D: Boiler Retrofit Emissions Reduction
Heat Input Boiler = 6.05 MMBtu/hr

HHV Natural Gas = 1020 Btu/SCF
x
NOx Emission Factor = 100 lb/MMSCF
=
Uncontrolled NOx Emissions = 0.593 lb/hr
Heat Input Boiler = 6.05 MMBtu/hr
x
Fd1 =8710 dscf/MMBtu
=
Exhaust Flowrate = 52,696 SCFH
x
MW NOx = 46.0055 lb/lbmol
x
NOx limit = 30 ppm

1E+06

MV = 385 ft3/lb-mol (standard molar volume)
=
Controlled NOx emissions = 0.189 lb/hr
Difference = 0.404 lb/hr
1.77 ton NOx/yr removed
Cost of Controls = 80,000$
45,184$ per ton NOx removed
Notes:
1 for natural gas (per Table 19-2, EPA Method 19)
BOILER #1
Heat Input Boiler = 6.28 MMBtu/hr

HHV Natural Gas = 1020 Btu/SCF
x
NOx Emission Factor = 100 lb/MMSCF
=
Uncontrolled NOx Emissions = 0.616 lb/hr
Heat Input Boiler = 6.28 MMBtu/hr
x
Fd1 =8710 dscf/MMBtu
=
Exhaust Flowrate = 54,699 SCFH
x
MW NOx = 46.0055 lb/lbmol
x
NOx limit = 30 ppm

1E+06

MV = 385 ft3/lb-mol (standard molar volume)
=
Controlled NOx emissions = 0.196 lb/hr
Difference = 0.420 lb/hr
1.84 ton NOx/yr removed
Cost of Controls = 80,000$
43,529$ per ton NOx removed
Notes:
1 for natural gas (per Table 19-2, EPA Method 19)
BOILER #1
Reasonably Available Control Technology Analysis for NOx

E
1_RACT Analysis

Attachment E: Cost Escalation

SCR Economic Feasibility
EPA’s "Alternative Control Techniques" Document (EPA-453/R-93-032) published in July 1993
Provides a cost effectiveness threshold for reduction of NOx from engines using SCR
890.00$ per ton in 1991 dollars
4889 Engineering News Record (ENR) Construction Cost Index (CCI) for 1991
13498 ENR CCI for October 2023 (20 Cities Average)
2,457$ per ton cost-effectiveness threshold escalated to 2023 dollars
Low NOx Burner Economic Feasibility
4,300$ per ton NOx reduction in 1992 dollars
5059 Engineering News Record (ENR) Construction Cost Index (CCI) for 1992
13498 ENR CCI for October 2023 (20 Cities Average)
11,473$ per ton cost-effectiveness threshold escalated to 2023 dollars
Table 2-7 of EPA's "Alternative Control Techniques Document -- NOx Emissions from Industrial /
Commercial / Institutional (lCI) Boilers" (EPA-453/R-94-022)