v>EPA
EPA 600/R-16/099 September 2016 j www.epa.gov/research
United States
Environmental Protection
Agency
Evaluating the Air Quality, Climate & Eco
nomic Impacts of Biogas Management
Technologies
Office of Research arid Development
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Evaluating the Air Quality, Climate & Economic Impacts of
Biogas Management Technologies
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EPA/600/R-16/099
September 2016
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EPA/600/R-16/099
September 2016
Evaluating the Air Quality, Climate
& Economic Impacts of Biogas
Management Technologies
UC Davis Biomass Collaborative (Davis, CA)
U.S. EPA Region 9 (San Francisco, CA)
& National Risk Management Research Lab
Office of Research and Development (Cincinnati, OH)
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Table of Contents
Acknowledgements & Notice vi
Foreword vii
Executive Summary viii
Summary Cost Results x
Summary Emissions Results x
List of Figures xiii
List of Tables xiv
Acronyms & Abbreviations xv
1. Introduction 1
2. Methods & Results 4
Assumptions 5
Biogas Composition 5
Cost of Energy 5
Criteria Pollutants 6
Greenhouse Gas Emissions 7
Results 8
Microturbine 8
Gas Turbines 14
Reciprocating Engines 18
Fuel Cell 25
Compressed RNG (on-site fuel) 28
Upgrade & Pipeline Injection 33
Flare 38
3. Results and Discussion 40
Primary Technology Costs 40
Criteria Pollutant Emissions 43
GHG Emissions 46
Comparison to eGRID 47
Additional Costs 49
Stationary Engines: Pre-Treatment 49
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Compressed RNG: Scale & Demand 50
Pipeline Injection: Scale, Clean-Up & Interconnection 51
Collecting & Processing High Strength Organic Wastes 51
Managing Digestate 52
Primary Revenue: Energy Savings, Sales & Subsidies 53
Offsetting Heat & Power Costs 53
Selling Excess Energy 53
Renewable Energy Certificates (RECs) 54
EPA's Renewable Fuel Standard & Renewable Identification Number (RIN) Credits 54
("ARB's I.CI S Credits 55
California's Carbon Offset Credits & Greenhouse Gas Reduction Fund 55
Additional Revenues: Tipping Fees & Co-Products 55
Policy Pipeline 57
Federal Policies 57
State of California Policies 59
4. Conclusions 62
Appendices 66
Appendix A- Technology Summary Results Data 67
Microturbines 67
Gas Turbines 68
Reciprocating Engines 69
Fuel Cells 70
RNG with On-site Fueling 71
Upgrade & Pipeline Injection 72
Flare 73
Appendix B- Grants & Other Financial Incentives 74
Compilation of Key Funding Sources 74
Federal & California Agency-Specific Funding 74
Appendix C- Source Test Data 76
References 79
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Acknowledgements & Notice
The authors include: Robert B. Williams, Development Engineer, University of California, Davis
(UCD) California Biomass Collaborative; Charlotte Ely, Life Scientist, U.S. Environmental
Protection Agency (EPA) Region 9 Pacific Southwest; Trina Martynowicz, Environmental
Protection Specialist, EPA Region 9; and Michael Kosusko, Chemical Engineer, EPA Office of
Research and Development (ORD).
Thank you to everyone who contributed your time and expertise to this research. The
participation of the Stakeholder Committee members throughout this process has proven
invaluable, as has the insight of those who participated in individual interviews.
We are indebted to EPA interns, who, over the course of several years helped us acquire and
organize data from air management districts. Thank you, Charlotte Hummer, Jason Jung, and
Sophia Rodriguez for all your help. The authors gratefully acknowledge the essential
participation by the following current and former EPA Region 9 staff - Laura Moreno, John
Mikulin, Cara Gillen, Steve Wall and Sara Rizk - and interns - William Smallen and Matthew
Ward - for helping to get this project off the ground. EPA's ORD staff that contributed to this
research includes Bob Wright for outstanding Quality Assurance support and Wendy Davis-
Hoover.
And finally, we would like to thank the support and assistance from Dr. Steve Kaffka, Director
of the California Biomass Collaborative, UCD.
This document has been reviewed by the U.S. Environmental Protection Agency, Office of
Research and Development, and approved for publication. Any mention of trade names,
products, or services does not imply an endorsement by the U.S. Government or the United
States Environmental Protection Agency. EPA does not endorse any commercial products,
services, or enterprises.
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Foreword
The U.S. Environmental Protection Agency (EPA) is charged by Congress with protecting the
Nation's land, air, and water resources. Under a mandate of national environmental laws, the
Agency strives to formulate and implement actions leading to a compatible balance between
human activities and the ability of natural systems to support and nurture life. To meet this
mandate, EPA's research program provides data and technical support to solve environmental
problems today and builds the science knowledge base necessary to manage our ecological
resources wisely, understand how pollutants affect our health, and prevent or reduce
environmental risks in the future.
The National Risk Management Research Laboratory (NRMRL) investigates technological and
management approaches to prevent and reduce risks from pollution that threaten human health
and the environment. The focus of the Laboratory's research program is to understand how
pollution enters the environment by investigating emissions and releases to air, water, land, and
sub-surfaces and to investigate technologies and approaches to prevent and control these sources
of pollution. The research is designed to protect water quality in public water systems; remediate
contaminated sites, sediments and ground water; prevent and control air pollutants in indoor and
outdoor environments; and restore ecosystems. NRMRL collaborates with both public and
private sector partners to foster technologies that reduce the cost of compliance and actively
works to identify/anticipate emerging problems. NRMRL's research provides solutions to
environmental problems by: developing and promoting technologies that protect and improve the
environment; advancing scientific and engineering information to support regulatory and policy
decisions; and providing the technical support and information transfer to ensure implementation
of environmental regulations and strategies at the national, state, and community levels.
This publication has been produced as part of the Laboratory's strategic long-term research plan.
It is published and made available by EPA's Office of Research and Development (ORD) to
assist the user community and to link researchers with their clients. It was funded by the
Regional Applied Research Effort (RARE) program, a national funding program responding to
the high-priority research needs of EPA Regions.
Gary J. Foley, Acting Director of the Air Pollution Prevention and Control Division
National Risk Management Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
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Executive Summary
Anaerobic digestion is a natural biological process in which microorganisms break down organic
materials in the absence of oxygen. When anaerobic microbes metabolize organic waste - i.e.,
the carbon-based remains of plants, animals and their waste products, e.g., animal manure,
sewage sludge and food waste - they produce biogas. Biogas consists mainly of methane and
carbon dioxide and can be used as a renewable energy fuel in a variety of applications. The costs
and impacts of biogas generation and utilization processes differ, depending on the scale,
technology, source material (e.g., sewage, manure, food processing waste, municipal solid
waste), and end uses (e.g., on-site electricity generation, conversion to a vehicle fuel, injection
into the natural gas pipeline).
This research was focused in California because it has unique air quality challenges that make it
difficult to comply with National Ambient Air Quality Standards (NAAQS) without installing
controls on a wide variety of sources.1 These difficulties are "due to the combination of
meteorology and topography, population growth and the pollution burden associated with mobile
sources" (USEPA 2015a). However, with the strengthening of NAAQS for ground level-ozone,
challenges unique to California could become more commonplace. As air quality regulators
across the country consider limits on stationary sources, insights from the proverbial 'canary in
the coal mine' may prove instructive.
Currently, many existing biogas producers [e.g., a Water Resource Recovery Facility (WRRF) or
landfill] are located in ozone non-attainment areas in California where there is pressure to
decrease stationary source emissions, especially from stationary reciprocating engines. Required
to meet more stringent emissions rules, many organic waste managers, project owners and
regulators alike lack sufficient information about the overall environmental and economic
performance of available biogas management technologies. A more complete understanding of
the environmental and economic performance of biogas-to-energy technologies will assist in
identifying geographically appropriate and cost-effective biogas management options. This
research attempts to advance that understanding through an evaluation of available biogas
management technologies and related performance in California.
The focus of the research described in this report was to evaluate the impacts associated with
biogas management technologies; specifically, to evaluate the emissions and costs associated
with using biogas in particular end-use applications. Seven different technologies were evaluated
in terms of their individual cost, efficiency and emissions both greenhouse gas (GHG) and
criteria air pollutant emissions. The technologies examined include: combustion in a
1 In general, emission limits are more stringent and concomitant installation and operating costs are higher in
California for these technologies. Forty-two California counties are designated non-attainment for the 8-hour ozone
(2008) standard; seven of which are designated as Serious, Severe or Extreme (USEPA 2012b). Affected population
is 34.6 million out of 39.1 million total state population (or 88% of total).
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reciprocating engine; combustion in a gas turbine; combustion in a microturbine; conversion in a
fuel cell; processing for pipeline injection; processing to create Compressed Natural Gas (CNG);
and flaring.2
The scope of the analysis was at once broad and narrow. It was broad in that it did not consider
differences in biogas composition, which vary considerably depending on the source material.
The analysis was narrow in that the system boundary began with already-produced biogas and
ended with on-site use or upgrading (Figure 1). It did not include the costs or emissions from
upstream processes, such as biogas production, fugitive emissions or material handling and
transportation costs.3 Neither did it include downstream factors, such as the carbon temporarily
sequestered by land-applying digestate or the carbon and criteria pollutants emitted by
combusting CNG in a vehicle. Comprehensively, the analysis evaluated capital, operations, and
maintenance costs, including those for biogas pre-treatment or conditioning (e.g., removing
siloxanes and sulfur compounds) and exhaust gas treatment (i.e., for air pollution control
equipment). Narrowly, it only evaluated costs pertaining to biogas management.
Direct Emissions from this Process:
Criteria Pollutants and Greenhouse Gases
A
BIOGAS INPUT
df
Conversion,
Processing
>
or Flare
Figure 1. System boundary.
Output Energy and Cost
to Produce Electricity or
Fuel/Pipeline Methane Product
The characteristics evaluated and compared through this research project included the following:
Conversion efficiency: percent energy efficiency for electricity production
systems, higher heating value basis and percent yield for compressed renewable
natural gas (RNG) and pipeline injection processes.4
Levelized cost of energy (LCOE): dollar per kilowatt hour ($/kWh), dollar per
million British thermal units ($/MMBtu) or $/gasoline gallon equivalent ($/GGE).
On-site criteria pollutant and GHG emissions.5
Only California-based systems were evaluated. Source information included peer-reviewed and
'gray' literature, operating permits, source test reports, and expert and developer interviews. Cost
2 Combined heat and power and direct use of biogas for heat or steam (boilers or furnaces) are not analyzed in this
report but are a viable option if a facility can use the heat, e.g., to warm digesters.
3 Although the cost of and emissions from processing wastes to generate biogas are significant factors in the
economics and enviromnental impacts of waste-to-energy projects, they are not considered here given the
availability of research focused on these issues and the limited resources available for this study.
4 Electrical energy output / biogas energy input on a higher heating value (HHV) basis.
5 Downstream emissions and costs for fuel and pipeline product are not included in this analysis.
IX
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and performance values in this report are suitable for comparing across technologies and for
rough budgetary estimates. Detailed project costs and, to some extent, performance are site
specific and would need to be assessed by a project developer.
Summary Cost Results
Costs required to process biogas varied from less than $l/MMBtu (input flow basis) for flare
systems to $7-$25/MMBtu or more for upgrading the biogas for injection into the natural gas
pipeline. Flaring appeared to be the lowest cost management option but would likely not be if
energy savings, sales, or subsidies were included in a future analysis.
Fuel cell costs were similar to those of upgrading for pipeline injection. Costs for engines,
microturbines and processing for CNG each fell below $5/MMBtu (input) for the upper end of
the technology capacity range. Combustion turbine costs were relatively flat ($3-$4/MMBtu).
Fuel cells, microturbines, processing to CNG and pipeline injection showed particularly strong
economies of scale due to a combination of lower per-unit capital and operating costs, and higher
efficiencies at larger scale. For situations where biogas is already available (e.g., landfills or
WRRFs), management of biogas using microturbines, reciprocating engines, and gas turbines
would compete with industrial and commercial electricity prices in CA.6
The LCOE for fuel cells ranged from ~$0.16/kWh at a small size (200 kW) to about $0.09/kWh
at the 3 MW size. The LCOE for reciprocating engines varied from $0.09 to $0.05/kWh.
Combustion turbines (gas turbines) had the lowest LCOE of about $0.04/kWh at large scale.
CNG production with on-site fueling varied from about $18/MMBtu to about $4/MMBtu at the
largest size. The CNG pathway was generally less costly than upgrading the gas for pipeline
injection, which ranged upwards from $25/MMBtu at small scale to about $7/MMBtu at very
large scale.
Summary Emissions Results
Criteria Pollutants7
Criteria pollutant emission factors, based on gas energy input (lb/MMBtu gas input), are
calculated and summarized in the report. Reciprocating engines had the highest NOx emission
factor among the technologies that produce on-site electricity, while flares had the highest
average NOx emission factor over all. Of the stationary power applications, fuel cells, followed
by gas turbines with selective catalytic reduction (SCR)-based NOx control systems, had the
lowest NOx emission factors.8
6 Average California electricity prices for industrial and commercial customers are $0.123/kWh and $0.156/kWh
respectively (EIA 2016). The expected Bioenergy Feed-in Tariff price floor is about $0.125/kWh.
7 See methods and individual technology descriptions in main body of report for details on emission factors.
8 Fuel cells employ an electrochemical method to produce electricity and therefore have very low air emissions.
Those emissions come from the combustion or oxidation of the anode off gas, which contains unreacted hydrogen
(H2), CO and VOCs. Catalytic or surface burners are usually used for the anode off gas. These operate at a high
enough temperature to oxidize the H2, CO, and VOCs while producing very low NOx emissions (ICF 2015).
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The CNG and pipeline injection pathways produce on-site emissions but are responsible for
additional emissions when the gas is used. Again, these downstream emissions are beyond the
scope of this analysis.
The report summarizes output-based NOx (lb/MWh of delivered electricity) for the electricity
producing systems. The effect of conversion efficiency can be seen in the output-based
emissions. Engines, gas turbines and microturbines all show decreasing output-based emissions
as capacity (and efficiency) increases. The efficiency of fuel cells is approximately constant over
the range of capacities modeled.
GHG
On-site emission factors for individual GHGs and output-based emissions in lb of CCheq per
MWh were developed for each technology in the report. All devices emit small amounts of
methane as "slip" (or unburned methane) from conversion devices or through leaks in processing
equipment. The analysis used a methane slip factor that ranged from 0.2 - 2.0% depending on
the device. The on-site CO2 emissions include the CO2 originally in the input biogas as well as
those created by combusting methane. Both of these sources of CO2 are biogenic.9 There are no
other CO2 emissions considered in this report.
The CO2 equivalent emission factors calculated in this report for biogas-fueled microturbines,
gas turbines, reciprocating engines, and fuel cells are all considerably lower than the California
electric grid average carbon footprint, which is 653 lb CCheq per MWh.10
Other Costs, Revenues & Policies
Recognizing the limited scope of the analysis and the important role of additional factors in
evaluating a project's economic and environmental performance, the report includes a qualitative
description of possible additional costs, such as acquiring a natural-gas powered fleet for the
CNG pathway; it also reviews possible sources of revenue, such as savings from on-site energy
use or income from off-site energy sales. Finally, the report provides an overview of major
Federal and State policies and subsidies affecting biogas projects, including a compendium of
grants & other financial incentives (Appendix B).
Relevance to other states or regions
While the biogas utilization technologies discussed in this report are in use throughout the U.S.,
the detailed emissions performance and costs are specific to California, where forty-two
California counties are designated non-attainment for 8-hour ozone (2008). In general, emission
limits are more stringent and concomitant installed and operating costs are higher in California
9 Biogenic CO2 emissions are those related to the natural carbon cycle, as well as those resulting from the
production, harvest, combustion, digestion, fermentation, decomposition, or processing of biologically based
materials (USEPA 2016).
10 See USEPA eGRID: https://www.epa. gov/energy/egrid. Biogenic CO2 emissions are not counted in the EPA
eGRID inventory. Biogenic CO2 emissions from this analysis were not included in order to compare to eGRID. The
Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive source of data on the
environmental characteristics of the electric power generated in the United States.
XI
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for these technologies. However, these results may soon have utility for many regions in the U.S.
The number (and severity) of ozone non-attainment areas are expected to increase after
implementing the more stringent 2015 ozone standard.
Xll
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List of Figures
Figure 1. System boundary ix
Figure 2. Ozone (O3) attainment designations in California for 8-hour 2015 National Ambient
Air Quality Standard (NAAQS) and biogas producers 2
Figure 3. General biogas production and use pathway schematic 3
Figure 4. System boundary 4
Figure 5. Microturbine schematic 9
Figure 6. Microturbine efficiency curve 10
Figure 7. Emissions vs. capacity for microturbines 11
Figure 8. LCOE for microturbines 13
Figure 9. Gas turbine schematic 14
Figure 10. Gas turbine efficiency curve 15
Figure 11. Emissions, "Low-NOx" combustion turbines 16
Figure 12. Emissions, combustion turbines w/ SCR NOx control 16
Figure 13. LCOE for combustion turbines 18
Figure 14. Reciprocating engine efficiency curve 19
Figure 15. NOx emission factor: engine source tests 20
Figure 16. CO emission factor: engine source tests 20
Figure 17. VOC emission factor: engine source tests 21
Figure 18. Emissions vs. capacity for reciprocating engines 22
Figure 19. LCOE for reciprocating engines 24
Figure 20. Schematic - internal reforming molten-carbonate fuel cell 25
Figure 21. LCOE - fuel cell 28
Figure 22. RNG process schematic 29
Figure 23. RNG process schematic with tailgas flare 30
Figure 24. RNG production cost estimates 32
Figure 25. Schematic - two-stage-membrane upgrade system 33
Figure 26. Upgrade-to-pipeline process schematic with tailgas flare 35
Figure 27. Upgrade and injection cost vs. capacity 38
Figure 28. Biogas processing costs 40
Figure 29. LCOE comparison 41
Figure 30. B&V LCOE estimates for biogas compared to this report 42
Figure 31. Biomethane product cost 42
Figure 32. Emission factors by technology 44
Figure 33. NOx emissions (lb/MWh) 44
Figure 34. CO emissions (lb/MWh) 45
Figure 35. VOC emissions (lb/MWh) 45
Figure 36. GHG emission factor summary (lb/MMBtu input) 47
Figure 37. Average methane emissions, bio-power technologies & CA eGRID 48
Figure 38. Average N2O emissions, bio-power technologies & CA eGRID 48
Figure 39. C02eq emissions for the bio-power technologies & CA eGRID 49
Figure 40. Biogas facilities and attainment designations for 2008 and 2015 ozone standard 58
Figure 41. C02eq emissions for the bio-power technologies & CA eGRID 63
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List of Tables
Table 1. Estimated biogas potential for California 1
Table 2. Number of source tests reviewed by application type 7
Table 3. Microturbine input flows and efficiency 9
Table 4. Microturbine emission factors: criteria pollutants 10
Table 5. CARB DG emission standards for biogas 11
Table 6. GHG emission factors - microturbines 12
Table 7. Output based GHG emissions - microturbines 12
Table 8. Microturbine cost analysis and LCOE 13
Table 9. Gas turbine input flows and efficiency 15
Table 10. Gas turbine emission factors: criteria pollutants 16
Table 11. Output based GHG emissions- gas turbines 17
Table 12. Combustion turbine cost analysis and LCOE 17
Table 13. Reciprocating engine input flows and efficiency 19
Table 14. Emission factors: reciprocating engines 21
Table 15. GHG emission factors - reciprocating engines 22
Table 16. Output based GHG emissions- reciprocating engines 23
Table 17. Reciprocating engine cost analysis and LCOE 24
Table 18. Fuel cell capacities and associated biogas input flows 26
Table 19. Criteria pollutant and GHG emissions from fuel cells 26
Table 20. Fuel cell capital costs from literature 27
Table 21. Fuel cell cost analysis and LCOE 28
Table 22. RNG input and output flow and energy 29
Table 23. RNG on-site criteria pollutant emissions 31
Table 24. RNG process GHG emissions 31
Table 25. RNG costs 32
Table 26. Upgrade-to-pipeline-injection input and product yield 34
Table 27. Upgrade-to-pipeline injection on-site criteria pollutant emissions 35
Table 28. Upgrade-to-pipeline-injection process GHG emissions 36
Table 29. Upgrade and injection cost modeling 37
Table 30. Flare emissions and emission factors 39
Table 31. Flare gas disposal cost 39
Table 32. Emission factor comparisons: criteria pollutants 43
Table 33. GHG emission factor summary 46
Table 34. Range and average costs of different biosolids management strategies 52
Table 35. 2016 Renewable Volume Obligations 54
xiv
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Acronyms & Abbreviations
ADC
Alternative daily cover
AFR
Air/fuel ratio
AD
Anaerobic digestion
ADWF
Average dry weather flow
BAAQMD
Bay Area Air Quality Management District
BACT
Best available control technology
B&V
Black and Veatch
BCF
Billion cubic feet
Btu
British thermal unit
CAPEX
Capital expenditure
CARB
California Air Resources Board
CEC
California Energy Commission
CI
Carbon intensity
CPUC
California Public Utilities Commission
C02
Carbon dioxide
CCheq
Carbon dioxide equivalent
CO
Carbon monoxide
CRNG
Coalition for Renewable Natural Gas
CHP
Combined heat and power
CNG
Compressed natural gas
CAFOs
Concentrated animal feedlot operations
DG
Distributed generation
DLN
Dry low-NOx
EBMUD
East Bay Municipal Utility District
Eq
Equivalent
FIT
Feed-in tariff
GGE
Gasoline gallon equivalent
GW
Gigawatt
GWP
Global warming potential
GWP100
100 year horizon GWP
GHG
Greenhouse gas
HHV
Higher heating value
h
Hour
h2
Hydrogen
h2s
Hydrogen sulfide
IEUA
Inland Empire Utilities Agency
IOU
Investor-owned utility
IPPC
Intergovernmental Panel on Climate Change
kWh
Kilowatt hour
LCA
Life-cycle analysis
LCOE
Levelized cost of energy
LNG
Liquefied natural gas
LCFS
Low carbon fuel standard
MW
Megawatt
MWh
Megawatt hour
ch4
Methane
MMBDT
Million bone dry (short) tons
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MMBtu Million British thermal units
MGD Million gallons per day
MCFC Molten carbonate fuel cell
NAAQS National Ambient Air Quality Standard
NOx Nitrogen oxides (or oxides of nitrogen)
N2O Nitrous oxide
NSCR Nonselective catalytic reduction
ORD Office of Research and Development
O&M Operation and maintenance cost
02 Oxygen
03 Ozone
OPEX Operations expense
PM Particulate matter
ppm Parts per million
ppmv Parts per million by volume
lb Pounds
PPA Power purchasing agreement
PSA Pressure swing adsorption
PAR Proposed amended rule
POTW Publicly owned treatment works
RICE Reciprocating internal combustion engines
RAM Renewable auction mechanism
REC Renewable energy certificate
RFS Renewable fuels standard
RIN Renewable identification number
RNG Renewable natural gas (also known as biomethane)
RPS Renewable portfolio standard
RVO Renewable volume obligation
SJVAPCD San Joaquin Valley Air Pollution Control District
SCR Selective catalytic reduction
SB Senate bill
SLCP Short-lived climate pollutants
SOFC Solid oxide fuel cell
SCAQMD South Coast Air Quality Management District
SCAP Southern California Alliance of Publicly-Owned Treatment Works
SCFM Standard cubic feet per minute
SO2 Sulfur dioxide
SOx Sulfur oxide
TS Total solids
EPA U.S. Environmental Protection Agency
UCD University of California, Davis
VOC Volatile organic compounds
VS/TS Volatile solids/Total solids
WRRF Water resource recovery facility (a.k.a., WWTF)
WWTF Wastewater treatment facility
y Year
xvi
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1. Introduction
Anaerobically digested (AD) organic waste produces biogas, a source of renewable energy. With
ample volumes of organic waste, California could generate a significant amount of renewable
energy. California biogas potential is estimated to be 93 billion cubic feet per year of methane or
about 800 million gallons gasoline equivalent (GGE) if used as compressed Renewable Natural
Gas (RNG), or CNG (Table 1) (Williams, Jenkins et al. 2015).
Table 1. Estimated biogas potential for California.
Feedstock
Amount
Technically
Available
Biomethane
Potential
(billion cubic feet)
Million gasoline
gallon equivalent
(GGE)
Animal Manure
3.4 MM BDT *
19.7
170
Landfill Gas
106 BCF *
53
457
Municipal Solid Waste
(food, leaves, grass fraction)
1.2 MM BDT
12.6
109
Water Resource Recovery
Facility11 (WRRF)
11.8 BCF (gas)
7.7
66
Total
93
802
* MM BDT = million bone dry (short) tons, BCF = billion cubic feet.
Many biogas producers generate electricity on-site with reciprocating engines, gas turbines and
microturbines, which emit ozone-forming criteria pollutants (i.e., nitrogen oxides or NOx). The
majority are located in ozone non-attainment air basins where strict regulation of criteria
pollutants complicates the permitting of stationary sources (Figure 2).
Innovative alternatives such as upgrading biogas for injection into natural gas pipelines, fuel
cells and the use of biogas as a transportation fuel can achieve cross-media environmental
benefits, including: GHG emission mitigation, air and water quality improvements, odors and
waste reduction, and fossil fuel displacement. However, organic waste managers and regulators
alike lack sufficient information about the overall environmental and economic performance of
available biogas management technologies.
11 WRRFs are also known as Wastewater Treatment Facilities (WWTF).
1
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CALIFORNIA BIOGAS PRODUCERS AND COUNTIES COMPARED AGAINST
- - Tl IE 0.070 PPM 201 5 8-HOUR OZONE STANDARD
11 i..'!1?. f
Biogas Producers
Stand-Alone Digester
Dairy with Digester
Landfill Collecting Biogas
Waste Water Treatment Facillity with Digester
Serious
Moderate
Marginal
County boundary
: iNf ~}"r ¦ tr. "
1 I I
I n«a|Dc*»«23 W1i|
tin. hTKt Dattnrm romTUn Interna; itmtwrt P Cap. GEBCQ U3C5 #AO. I
MUCAN C-iflcn. IGN K.Mar ft CMMm 5ir»|i £«i Jip.r Veil Cai dim .|*sns *
J. [MtiMBMa <«) j C< CV«<8T4«IU((i wmwjo ...J to Produce Electricity or
Fuel/Pipeline Methane Product
14 U.S. EPA Landfill Methane Outreach Program: https://www3.epa.gov/lmop/proiects-candidates/operational.html
15 U.S. DOE CHP Technical Assistance Partnerships, Pacific Region: http://www.pacificchptap.org/aboutchp
4
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The properties and characteristics evaluated and compared include the following:
Conversion efficiency: percent energy efficiency for electricity production systems, higher
heating value basis and percent yield for compressed RNG and pipeline injection processes.16
Levelized cost of energy (LCOE): dollar per kilowatt hour ($/kWh), dollar per million British
thermal units ($/MMBtu) or $/gasoline gallon equivalent ($/GGE).
On-site criteria pollutant and GHG emissions.17
Source information included peer-reviewed and 'gray' literature,18 operating permits and source
test reports and expert and developer interviews.
Assumptions
Biogas Composition
Methane content in biogas ranges from 40-65% in landfill gas and 50-75% in digester gas
(Mintz, Han et al. 2010, Rapport, Zhang et al. 2012). Raw biogas also contains water vapor and
typically includes hydrogen sulfide (H2S) and possibly siloxanes.19 Hydrogen sulfide is
corrosive, can contribute to sulfur oxide (SOx) emissions and can damage catalysts used in air
pollution control systems and most fuel cells. Siloxanes are problematic because they can lead to
deposits of silicon compounds (such as SiCh) in an engine or turbine when the biogas is
combusted as well as damage to emissions control catalysts. Consequently, raw biogas often
needs to be cleaned or treated to lower H2S and siloxane content to acceptable levels (GTI2014).
In this report, methane content of biogas is assumed to be 60% (with balance of carbon dioxide).
The cost evaluations include those associated with removing biogas impurities (e.g., siloxanes
and sulfur compounds) for the respective application.
Cost of Energy
Capital and operating costs for the biogas technologies are taken from literature and discussions
with developers; those costs reflect California costs or "adders" to U.S. average costs. Costs of
raw biogas cleanup (H2S and siloxane reduction) are included for all biogas technologies. Cost of
air pollution control equipment is included for reciprocating engines and gas turbines; air
pollution control equipment is presumed not needed for microturbines, fuel cells, fuel and
pipeline pathways, and flares. The CNG fueling pathway cost includes on-site fueling
equipment. The upgrade to pipeline injection pathway includes interconnection or injection
costs. Year 2015 dollars are used.
16 Electrical energy output / biogas energy input on a higher heating value (HHV) basis.
17 Downstream emissions and costs for fuel and pipeline product are not included in this analysis.
18 http://www.grevnet.org/home/aboutgrevnet.html
19 Siloxanes are synthetic organo-silicon compounds used in the manufacturing of personal hygiene, health care and
industrial products. Their prevalence results in the lower molecular weight siloxanes being released into landfill gas
and some wastewater treatment digester gas.
5
-------
The LCOE was estimated for each technology by dividing the total annual cost by the annual
amount of energy produced to arrive at cost per unit of energy: $/kWh, $/GGE, or $/MMBtu.
Total annual cost is the sum of the annualized capital cost and annual operation and maintenance
(O&M) costs. The capital cost was amortized over 20 years using 6% annual interest to
determine the annualized capital cost.
The LCOE represents the required revenue per unit of energy for the project to break even. Note
that the analysis assumed the infrastructure needed to produce the biogas already existed (or was
already paid for) and so biogas enters the economic calculation at zero cost.20
Criteria Pollutants
A large number of operating air permits and approximately 54 emission source test reports were
obtained from air districts throughout California. Criteria pollutant emission factors based on
fuel-energy input [i.e., pounds of pollutant per MMBtu input (lb/MMBtu)] were derived from a
review of source test reports for microturbines, combustion turbines and flares (Table 2 and
Appendix C).
For reciprocating engines, the nitrous oxide (NOx) emission factor is based on the South Coast
Air Quality Management District (SCAQMD) Rule 1110.2. Volatile organic compounds (VOC)
and carbon monoxide (CO) emission factors are based on source test data for engines with SCR
and catalytic oxidation (CatOx) exhaust treatment. These engine emission factors, therefore,
represent expected performance for new installations (or emissions retrofits) for the SCAQMD
and possibly other air districts at risk for meeting ambient ozone standards.
U.S. EPA AP-42 was used as the particulate matter (PM) emissions factor for reciprocating
engines and gas turbines. Source test data was used for PM otherwise.
Source test averages were used for oxides of sulfur (SOx) emission factors. Sulfur content in
biogas is highly variable and directly affects SOx emissions. The values shown here include the
influence of the biogas sulfur. Additionally, most catalysts used in emissions control equipment
are sensitive to sulfur and will fail quickly if most of the sulfur is not removed before it reaches
the catalyst. The SOx emission factors for those systems (SCR/CatOx) are therefore low.
Fuel cell emissions are based on permit values and one source test report.
On-site criteria pollutant emissions from producing compressed RNG and pipeline quality gas
are based on flaring the tailgas, a process byproduct gas which contains some methane that needs
to be destroyed. Downstream emissions also occur when the upgraded biogas is used, as a
vehicle fuel or as pipeline natural gas. Those downstream emissions are not included in this
analysis.21
20 If the biogas did not yet exist, e.g., a digester needed to be built, the economics would be different and the LCOE
likely higher.
21 These "downstream" emissions are important but there are too many possible factors (devices) to account for in
this analysis.
6
-------
Table 2. Number of source tests reviewed by application type.
Application*
No. of Source
Tests Reviewed
Biogas Source Type
Source Test Air District
Reciprocating
Engine
35
6 @ Landfill,
26 @ WRRF,
3 @ Dairy Digester
- South Coast
- Bay Area
- San Joaquin Valley
- Yolo-Solano
- Mojave Desert
Microturbine
4
1 @ WRRF,
3 @ Food Waste Digester
- South Coast
- Bay Area
Combustion
Turbine
10
5 @ Landfill,
5 @ WRRF
- South Coast
- Bay Area
- San Joaquin Valley
Fuel Cells
3 (2 permits)
3@ WRRF
- South Coast
- San Joaquin Valley
Flare
4
1 @ Landfill,
3 @ WRRF
- South Coast
- San Joaquin Valley
* Also see Appendix C.
Emission factors combined with conversion efficiencies were used to develop emissions per unit
of energy output (i.e., lb/MWh) for electricity producing technologies.
Greenhouse Gas Emissions
GHG emissions include methane (CH4) slip or fugitive emissions, nitrous oxide (N2O) and
carbon dioxide (CO2) emissions.
Methane slip (or unburned methane) from combustion devices is small but significant ranging
from 0.2 - 2.0% depending on the device (Mintz et al., 2010, SCS 2007). For the biomethane
pathways (compressed RNG and pipeline injection), 1% fugitive methane is assumed in the
upgrading process (Han, Mintz et al. 2011).
The N2O emissions are taken from source-specific literature when found. Otherwise, default N2O
emission factors for stationary combustion in the energy industry were used from Table 2.2 in
the 2006 Intergovernmental Panel on Climate Change (IPCC) Guidelines for National
Greenhouse Gas Inventories (IPCC 2006).
The CO2 emissions are calculated based on stoichiometric combustion of biogas where 1 gram of
methane produces 2.75 grams of carbon dioxide when burned (or 2.75 lb/lb). Emissions include
the CO2 present in the incoming biogas, which passes through the combustion process
unchanged, and the CO2 produced when methane is combusted. For biogas with 60% methane
7
-------
content, the CO2 emission factor is 0.115 lb CO2 per cubic foot of biogas (or 191.3 lb/MMBtu).22
All engine types, flaring, and other stationary applications that burn the same biogas type will
have equivalent CO2 emission factors. While there are fewer on-site CO2 emissions associated
with upgrading biogas to be used as a vehicle fuel or injected into the natural gas pipeline, once
combusted, the total CO2 emissions (on-site + off-site) would be the same as they are for engines
and for flaring.
No matter the end-use, CO2 emissions from combusting biogas are biogenic. The EPA defines
biogenic CO2 emissions as those related to the natural carbon cycle, as well as those resulting
from the production, harvest, combustion, digestion, fermentation, decomposition, or processing
of biologically based materials (USEPA 2016). The CO2 emissions associated with all of the
biogas management technologies evaluated herein are biogenic. There are no other CO2
emissions considered in this report.
The report compares the CO2 equivalent (CCheq) emission factors for biogas-fueled
microturbines, gas turbines, reciprocating engines, and fuel cells to the California electric grid
carbon footprint, which is 653 lbs C02eq per MWh, according to the EPA's eGRID. Consistent
with eGRID, biogenic CO2 emissions were not used to calculate CC>2eq emissions. 23
Results
Microturbine
Microturbines are small combustion turbines available in capacities ranging from 30 kW to 333
kW for individual units and up to multiple megawatt (MW) facility sizes if units are combined.
Electricity conversion efficiency ranges from about 22% to 27% (Figure 12). With biogas fuel,
NOx emissions are typically lower than 9 parts per million by volume (ppmv).
Like the larger combustion turbine, the microturbine operates on the Brayton Cycle
(thermodynamic cycle) where inlet air is first compressed followed by injection of gaseous or
liquid fuel and then burned in the combustor. The hot high-pressure combustion gas expands
through a turbine which provides shaft power to run the compressor and the electric generator
(Figure 5).
22 Emission factor of fossil natural gas is ~ 115 -125 lb CC^eq/MMBtu,
(https://www.eia.gov/environment/emissions/co2 vol mass.cfm)
23 USEPA eGRID assigns zero CO2 emissions to electric generation carbon footprint from the combustion of all
biomass (including biogas) because these organic materials would otherwise release CO2 (or other greenhouse
gases) to the atmosphere through decomposition: https://www.epa.gov/sites/production/files/2015-
10/documents/egrid2012 technicalsupportdocument.pdf.
8
-------
Power Exhaust Heat
Gearbox
I Compressor I
-M
Turbine
(adapted from FlexEnergy)
Figure 5. Microturbine schematic.
Efficiency
Electrical conversion efficiencies for microturbines (with recuperators) fueled on biogas range
from about 22% to 27% [higher heating value (HHV) basis] (Itron 2011, Darrow, Tidball et al.
2015, FlexEnergy). Table 3 displays nominal electrical conversion efficiencies and
corresponding gas energy input flows for typical microturbines.24 Efficiency versus capacity is
plotted in Figure 6 and includes the curve fit through the individual data.
Table 3. Microturbine input flows and efficiency.
Capacity
Efficiency,
HHV basis
kW
Gas Flow input
(SCFM)*
Gas Flow
input
(MMBtu/h)
(%)
Heat Rate
(Btu/kWh)*
30
13.1
0.47
22
15,700
65
26.4
0.95
23
14,600
200
73.5
2.6
26
13,200
250
90.0
3.2
26
13,000
333
116.9
4.2
27
12,600
* Note: SCFM = Standard cubic feet per minute. Heat Rate is Btu input energy per kWli electricity out
24 Sea level and ambient air temperature at 60 °F. Input flow calculations assume biogas is 60% methane or lias
energy content of 600 Btu per cubic foot.
9
-------
30
28
>"
x
^ 26
NO
>
c 24
QJ
o
it
m 22
20
0 50 100 150 200 250 300 350
Capacity (kW)
Sources: (Itron 2011, Darrow et ah, 2015, FlexEnergv)
Figure 6. Microturbine efficiency curve.
Microturbine efficiency is sensitive to the density of air at point of use. Conversion efficiency
and power output decrease as ambient temperature or elevation increases (due to lower air
density - less oxygen per cubic foot available for combustion).
Emissions
Criteria Pollutants
Uncontrolled emissions from natural gas-fired microturbines typically range 3-9 ppm for NOx,
VOC and CO (Darrow, Tidball et al. 2015). Source tests from microturbines in the Bay Area Air
Quality Management District (BAAQMD) and the SCAQMD were reviewed (Appendix C).
Both were for Ingersoll Rand (now FlexEnergy) 250 kW microturbines with no exhaust gas
aftertreatment. Criteria pollutant emission factors (lb/MMBtu) for microturbines were derived
from source test averages (Table 4 ).
Table 4. Microturbine emission factors: criteria pollutants.
Pollutant
(lb/MMBtu)
Associated Concentration
(PPM @15% 02)
NOx
0.016
4.2
CO
0.017
7.2
VOC
0.008
5.8
PM (total)
0.001
not indicated as concentration
SOx
0.067
13
/ = 16.084X00892
R2 = 0.9359
\
10
-------
Using the emission factors in Table 4 and the conversion efficiencies in Table 3, representative
output-based emissions estimates for microturbines of different capacities are shown in Figure 7.
Capacity (kW)
Figure 7. Emissions vs. capacity for microturbines.
Prior to 2013, a number of biogas fueled microturbines were certified to meet the California Air
Resources Board (CARB) distributed generation (DG) emission standards (0.5, 6, and 1 lb/MWh
for NOx, CO and VOC, respectively). After January 2013, the DG emission standard for biogas
fueled devices, including microturbines, became stricter (Table 5).25 There are currently no
biogas fueled devices certified to meet the DG standard.26 Biogas devices can still be permitted
through local air districts (and local regulations and emission limits).
Table 5. CARB DG emission standards for biogas.
Pollutant
Emission Standard
lb/MWh)
Jan. 1, 2008 to
Dec. 31, 2013
After Jan. 1, 2013
NOx
0.5
0.07
CO
6
0.1
VOC
1
0.02
25 See: http://www.arb,ca.gov/energy/dg/eo/eo-expired.htm
26 http ://www. arb. ca.gov/energy/dg/eo/eo-current. htm
11
-------
GHG
The GHG emission factors for microturbines are shown in Table 6. The methane emission factor
is based on a destruction efficiency of 99.6% [average of turbine source tests from (SCS 2007)
and default value in (CAR 2011)]. The emission factor for N2O is derived from IPCC guidelines
(IPCC 2006). The CO2 emission factor is calculated assuming stoichiometric combustion of
biogas (60% methane). The CO2 emissions are biogenic.
Table 6. GHG emission factors - microturbines.
GHG Emission Factors (Ib/MMBtu)
ch4
C02
N20
0.167
191.3
0.00026
Output based on GHG emissions [lb CCheq/MWh] are estimated by microturbine size in Table 7.
These are based on the emission factors in Table 6, conversion efficiencies (Table 3) and the
appropriate 100 year horizon global warming potentials (GWP100).27
Table 7. Output based GHG emissions - microturbines.
Capacity
(kW)
GHG (lb C02eq/MWh)
ch4
CO2*
N20
30
88.8
3,000
1.19
65
82.9
2,800
1.11
200
75.0
2,530
1.01
250
73.5
2,480
0.99
333
71.7
2,420
0.96
*Biogenic CO2 emissions
27 GWP100 = 34, 298 and 1 for CH4, N20, and CO2, respectively, based on the IPCC Fifth Assessment Report (AR5)
[IPCC 2013],
12
-------
Cost
Biogas fueled microturbines have installed costs that range from more than $6,800/kW for a 30
kW unit to about $3,610/kW for the 333 kW size (Table 8). Estimated LCOE ranges from
$126/MWh to $64/MWh for the 30 kW and 333 kW sizes respectively (Table 8 and Figure 8).
Table 8. Microturbine cost analysis and LCOE.
Capacity
(kW)
Electricity
Production
(kWh/y)a
Installed Cost
Total Capital
Annual
Debt &
Interest
($)d
Capital
Cost
($/kWh)
Turbine
O&M
($/kWh)e
Clean
up O&M
($/kWh)
LCOE
($/kWh)
Turbine,
w/o gas
cleanup
($/kW)b
Gas
Cleanup
($/kW)c
($/kW)
Total ($)
30
223,000
4,300
2,590
6890
207,000
18,000
0.081
0.02
0.026
0.126
65
484,000
3,220
1,930
5150
335,000
29,200
0.060
0.018
0.016
0.094
200
1,490,000
3,150
1,250
4400
880,000
76,700
0.052
0.017
0.008
0.076
250
1,860,000
2,720
1,150
3870
968,000
84,400
0.045
0.016
0.007
0.068
333
2,480,000
2,580
1,030
3610
1,200,000
105,000
0.042
0.016
0.006
0.064
Notes:
a. At 85% capacity factor.
b. Darrow, K R. Tidball, J. Wang and A. Hampson (2015). Catalog of Combined Heat and Power (CHP)
Technologies. ICF, EPA CHP Partnership.
c. Gas Cleanup Cap Cost - Based on cleanup equipment costs for two recent microturbine projects in CA.
d. 20 years 'a. 6% annual interest rate (or cost of money).
e. Based on average of service maintenance contracts for natural gas fueled units in ICF (2008). Catalog of CHP
Technologies, EPA CHP Partnership.
Capital costs are based on installed costs for natural gas fired systems (Darrow, Tidball et al.
2015) plus gas cleaning costs for biogas fueled microturbines (Tourigny 2014). Total installed
costs ($) are annualized over 20 years at 6% interest rate. O&M costs are derived from (ICF
2008, GTI2014).
0.14
0.12
0.10
0.08
5
< 0.06
w
0.04
0.02
0.00
BO
65
200
Capacity (kW)
250
333
Figure 8. LCOE for microturbines.
13
-------
Gas Turbines
Gas turbines (or combustion turbines) operate on the same thermodynamic cycle as
microturbines (Brayton Cycle) but their larger capacities range from about 1 MW (1,000 kW) to
500 MW for a single unit (Figure 9). Systems used for biogas applications range up to about 7.9
MW. Electricity conversion efficiency, for simple-cycle application, ranges from about 21% to
Biogas fueled combustion turbines in California include two at the Altamont landfill (3 MW
each), two at the Fresno-Clovis water resource recovery facility (-3.5 MW each), three at the
Calabasas landfill (~4 MW each), four at Brea-Olinda Landfill (5.6 MW each), five at Sunshine
Gas Producers, LLC Sylmar (4.9 MW each), two at Amaresco Chiquita Energy, Landfill
Valencia (Castaic) (4.6 MW each) and one at East Bay Municipal Utility District (EBMUD)
wastewater facility (4.5 MW).
(Adaptedfrom Energy Solutions Center httn:/M>inc. understandinzchy. com)
Figure 9. Gas turbine schematic.
Efficiency
Electrical conversion efficiencies for gas turbine generators fueled on biogas range from about
21% to 31% (HHV basis, 60 °F ambient air temperature) (Itron 2011, Kawasaki_Gas_Turbines
2015, Solar_Turbines 2015). Energy inputs range from about 20 MMBtu/h to 87 MMBtu/h for
1,200 kW and 7,900 kW respectively (Table 9). Efficiency versus capacity is plotted in Figure 10
and includes the curve fit through the individual data. As with microturbines, efficiency and
output decreases as ambient temperature or site elevation increases.
31%.
High Pressure
Compressor
To Exhaust or
Post-Combustion
Emission Controls
Low Pressure Intercooler \
Compressor \
aS/VaST Turbine
Cooling Media 'x/VN/- (drives compressor)
' Power
Turbine
14
-------
Table 9. Gas turbine input flows and efficiency.
Capacity
Efficiency, HHV basis
kW
Gas Flow in
Gas Flow in
Heat Rate
(SCFM)
(MMBtu/h)
(/o)
(Btu/kWh)
1200
540
19.5
21
16,300
3500
1310
47.1
25
13,500
4600
1630
58.8
27
12,800
5700
1890
67.9
29
11,900
6300
2000
71.9
30
11,400
7900
2400
86.5
31
10,900
Figure 10.
Gas Turbine eff.
012345678
Capacity (MW)
Sources: (Itron 2011, Solar Turbines 2015, Kawasaki Gas Turbines 2015)
Gas turbine efficiency curve.
Emissions
Criteria Pollutants
Uncontrolled emissions from natural gas-fired combustion turbines typically range 15-25 ppm
for NOx, 25-50 ppm for CO and ~5 ppm for VOC (Darrow, Tidball et al. 2015). Source tests
from biogas fueled gas turbines in the San Joaquin Valley Air Pollution Control District
(SJVAPCD), BAAQMD and SCAQMD were reviewed (see Appendix C). Turbines with lean
pre-mix combustor designs [Dry Low-NOx or (DLN)] had average NOx emissions of 8 ppm.
Systems with selective catalytic reduction (SCR) NOx control averaged 2.9 ppm NOx (Table 10).
Emission factors (lb/MMBtu), based on source test averages are also displayed in Table 10.
15
-------
Table 10. Gas turbine emission factors: criteria pollutants.
Low-NOx Combustor Design
SCR NO* Control
Uncontrolled*
(Ib/MMBtu)
ppm (@15% 02)
(Ib/MMBtu)
ppm (@15% 02)
(Ib/MMBtu)
NOx
0.031
8.0
0.011
2.9
0.16
CO
0.004
1.5
0.013
5.4
0.44
voc
0.007
5.3
0.001
0.5
0.013
PM (total)
0.012
not measured
0.012
not measured
0.023
sox
0.063
12.2
0.005
1.0
Depends on input
* Source: US EPA AP-42, Chapter 3.
Output-based emissions (i.e., pounds pollutant per MWh output) for biogas combustion turbines
with low-NOx burners and with SCR NOx control are displayed in Figure 11 and Figure 12. The
output-based emissions were estimated using the emission factors in Table 10, and conversion
efficiencies in Table 9.
0.60
0.50
| 0.40
tft
_Q
^ 0.30
£
| 0.20
E
LU
0.10
0.00
1000 3000 5000 7000 1000 3000 5000 7000
Capacity(kW) Capacity(kW)
Figure 11. Emissions, "Low-NOx" combustion Figure 12. Emissions, combustion turbines w/
turbines. SCR NOx control.
GHG
Emission factors for GHGs are assumed to be the same as for microturbines (Table 6).
Output based GHG emissions (lb C02eq/MWh) for gas turbines are estimated using the GHG
emission factors, conversion efficiencies and respective GWPioo.28
Low-NOx
combustors
0.60
0.50
S 0.40
E. 0.30
V)
c
o
\ 0.20
E
LU
0.10
n nn
W/ SCR c
NOx com
»r "ultra-low"
bustors
NOx
PM
VOC
cc
D
28 GWPioo = 34, 298 and 1 for CH4, N2O, and CO2, respectively.
16
-------
Table 11. Output based GHG emissions- gas turbines.
kW
Gr
(1
eenhouse Gases
b C02eq/MWh)
ch4
C02*
N20
1200
92.3
3,110
1.24
3500
76.3
2,580
1.03
4600
72.5
2,450
0.98
5700
67.5
2,280
0.91
6300
64.7
2,180
0.87
7900
62.1
2,090
0.83
*Biogenic CO2 emissions
Cost
Installed cost for the combustion turbines ranges from $5,300/kW for the 1,200 kW size to about
$2,500/kW for 7,900 kW (Table 12). Estimated LCOE ranges from $80/MWh to $42/MWh for
the capacities reviewed (Table 12 and Figure 13).
Table 12. Combustion turbine cost analysis and LCOE.
Capacity
(kW)
Electricity
Production
(kWh/y)a
Component Costs
Total Capital
Annual
Debt &
Interest
($)e
Capital
Cost
($/kWh)
Turbine
O&M
($/kWh)f
Clean
up O&M
(S/kWh)g
LCOE
($/kWh)
Turbine
system
($/kW)b
Gas
Cleanup
($/kW)c
Emissions
Control
($/kW)d
($/kW)
Total
Installed
($)
1200
8,935,000
4,390
310
624
5320
6,384,000
557,000
0.062
0.015
0.0028
0.080
3500
26,060,000
2,990
148
333
3470
12,150,000
1,060,000
0.041
0.013
0.0014
0.055
4600
34,250,000
2,710
122
284
3120
14,350,000
1,250,000
0.036
0.012
0.0011
0.050
5700
42,440,000
2,510
104
250
2860
16,300,000
1,420,000
0.034
0.012
0.0010
0.047
6300
46,910,000
2,420
96
236
2750
17,330,000
1,510,000
0.032
0.012
0.0009
0.045
7900
58,820,000
2,230
82
207
2520
19,910,000
1,740,000
0.029
0.012
0.0008
0.042
Notes:
a. At 85% capacity factor.
b. Darrow, K., R. Tidball, J. Wang and A. Hampson (2015). Catalog of CHP Technologies. ICF, EPA CHP
Partnership.
c. Gas Cleanup Cap Cost - siloxane removal curve fit 35064 X0375, Figure 11 from:
GTI (2014). Conduct a Nationwide Survey of Biogas Cleanup Technologies and Costs, Final Report, SCAQMD
Contract #13432.
d. ICF (2012). Combined Heat and Power Policy Analysis and 2011-2030 Market Assessment, Consultant Report to
the California Energy Commission (CEC). CEC-200-2012-002.
e. 20 years @ 6% annual interest rate (or cost of money).
f. Based on average of service maintenance contracts for natural gas fueled units in ICF (2008). Catalog of CHP
Technologies, EPA CHP Partnership.
g. Cleanup O&M Cost - siloxane removal curve fit 2047X0 3988, Figure 12 from: GTI (2014). Op. Cit.
17
-------
0.10
0.08
0.06
IE"
5
§ 004
LLI
O
u
-1 0.02
0.00
1200 3500 4600 5700 6300 7900
Capacity (kW)
Figure 13. LCOE for combustion turbines.
Reciprocating Engines
Reciprocating internal combustion engines (RICE) are used extensively throughout the world for
stationary power generation with some 12 million units produced in 2014 (237 million engines
were produced for all applications) (Huibregtse 2014). Reciprocating engine-generators are
typically the lowest cost systems for capacities from <100 kW to approximately 10 MW.
Reciprocating engines for biogas applications have been used extensively throughout California.
Untreated exhaust emissions from reciprocating engines, especially NOx, are among the highest
of the biogas utilization technologies.
Biogas fueled engines are usually adapted from natural gas engines which operate on the 4-
stroke, spark-ignited Otto cycle. There are two general classes of this type of engine; rich-burn
and lean-burn.
Rich-burn engines, sometimes called stoichiometric engines, operate on an air fuel ratio (AFR)
that is nearly stoichiometric, or exactly enough air to completely burn the fuel. Compared to
lean-burn, rich-burn engines generally produce lower hydrocarbon emissions but higher NOx
emissions. Rich-burn engines are required for use with the basic three-way (NOx, CO,
hydrocarbons) nonselective catalytic reduction (NSCR) catalyst system used in most gasoline-
fueled automotive applications.
Lean-burn engines use up to twice the amount of air needed for fuel combustion. This results in
lower peak combustion temperatures which translates into lower NOx production but can have
higher products of incomplete combustion (hydrocarbons or VOC) compared to rich-burn. Lean-
burn engines can have slightly higher fuel efficiency. Lean-burn engines must use selective
catalytic reduction with urea injection for further NOx reduction and oxidation catalysts for CO
and VOC reduction. A new LFG-to-energy project at the Bowerman landfill in Orange County,
CA is being commissioned. Seven Caterpillar CG260 3.37 MW lean-burn reciprocating engine-
generators with SCRNOx control and oxidation catalyst for VOC and CO control are installed
(23.5 MW nameplate capacity) [SCAQMD 2014b],
18
-------
Efficiency
Efficiency of biogas-fueled stationary engine-generator systems varies from about 25% for 100
kW units to 40% at the -4-5 MW size (Figure 14). Efficiency data were accumulated from
several sources and charted below. A logarithmic curve fit to the data was used for efficiency
values when analyzing engine output-based emissions (Table 13).
0.50
0.45
I
1/1
'l/1
TO
0.40
>
I
I
>:
u
c
0.35
QJ
U
£
LU
0.30
(13
U
m 0.25
QJ
C
E
LU
y = 0.0396ln(x) + 0.0562
R2 = 0.8043
0.20
0.15
0
1000
2000
3000
4000
5000
6000
Output Capacity (kWe)
Sources; (ICF 2012, Rutgers 2014, Caterpiller 2015)
Figure 14. Reciprocating engine efficiency curve.
Table 13. Reciprocating engine input flows and efficiency.
Capacity
Energy Efficiency, HHV basis
kW
Biogas Flow input
(SCFM)
Gas Flow input
(MMBtu/h)
(%)
Heat Rate
(Btu/kWh)
100
40
1.4
24
14,300
150
56
2.0
26
13,400
190
68
2.5
26
12,900
220
77
2.8
27
12,600
300
100
3.6
28
12,100
420
130
4.9
30
11,600
600
180
6.6
31
11,000
800
240
8.5
32
10,600
1000
290
10.3
33
10,300
1550
420
15.2
35
9,800
2000
530
19.1
36
9,600
3000
760
27.4
37
9,100
19
-------
Emissions
Criteria Pollutants
Some thirty-one source tests for biogas fueled reciprocating engines in California were reviewed.
Most were located in the BAAQMD and SJVAPCD and were permitted for 65-70 ppm NOx.
Also reviewed were three years of source tests for an engine permitted for 11 ppm NOx at a dairy
in the SJVAPCD that uses SCR for NOx reduction. Emission factor data for the reciprocating
engine source tests appear in Figure 15 through Figure 17 for NOx, CO and VOC respectively
(lb/MMBtu).
The average NOx emission factor for engines permitted in the 60-70 ppm NOx range is 0.128 lb-
NOx/MMBtu (33 ppm) (Figure 15).
~ 0.35
| 0.30
^ 0.25
l/l
§. 0.20
l/l
I 015
\A
0.10
£
£ 0.05
Z 0.00
0 500 1000 1500 2000 2500
Power output during source test (kW)
NOx - Reciprocating Engine Source Tests
P
\ *
verage = 0.12
A
V
u
irithmetic mean)
».*
t
**
r. -n
11 ppm NOx - (
J.042 Ibs/MMBtu
Note: Orange data points from engines with SCR and CatOx emission control systems (next two figures as well).
Figure 15. NOx emission factor: engine source tests.
1.0
- 0.9
| 0.8
S 0.7
J 0.6
r 0.5
.1 0.4
(S>
« 0.3
m 0.2
O
<-» 0.1
0.0
CO- Reciprocating Engine Source Tests
^
[ *
Average = 0.49
*-
(arithmetic meant)
¦
F
1 1
500 1000 1500 2000 2500
Power output during source test (kW)
Figure 16. CO emission factor: engine source tests.
20
-------
^018
"s"
| 0.15
^ 0.12
-Q
=-0.09
l/l
c
.2 0.06
l/l
£ 0.0B
O 0.00
0 500 1000 1500 2000 2500
Power output during source test (kW)
VOC - Reciprocating Engine Source Tests
0
Average = 0.04
arithmetic mean)
t
*
Figure 17. VOC emission factor: engine source tests.
The SCAQMD has been working on an amendment to its rule for emissions for stationary
engines for several years (Rule 1110.2). The amended rule specifies new emission limits for
biogas-fueled engines effective January 1, 2017 of 11 ppm NOx, 250 ppm CO and 30 ppm VOC
(SCAQMD 2015). These limits are equivalent to 0.043, 0.59 and 0.041 lb/MMBtu for NOx, CO
and VOC respectively (Table 14). For purposes of engine emission factors for the side-by-side
comparisons with other technologies in this report, Rule 1110.2 limits for NOx, CO and VOC are
used, along with the average source-test sulfur dioxide (SO2) value and the PM value from EPA
AP-42 (Table 14). Output-based emissions (lb/MWh vs Capacity) for engines are displayed in
Figure 18. Rule 1110.2 levels forNOx, VOC and CO are used in Figure 18.
Table 14. Emission factors: reciprocating engines.
(lb/MMBtu)
NOx
CO
VOC
S02
PM
Source test averages
(Pre-Rule 1110.2)
0.128
0.49
0.038
0.037
insuff.*
Source test averages
(Engines w/ SCR & OxCat)
0.037
0.151
0.016
0.003
insuff.
SCAQMD Rule 1110.2
(implements 1 January 2017)
0.043
0.59
0.041
n/a*
n/a
EPA AP-42
n/a
n/a
n/a
n/a
0.014
Emission Factors used in side-
by-side comparison - this report
0.043
0. 151
0.016
0.003
0.014
*Notes: insuff. => insufficient number of source tests had PM results to use for average
n/a=> not applicable or not used
21
-------
2.0
1.5
2"
§
^ 1.0
0.5
0.0
0 500 1000 1500 2000 2500 3000
Capacity (kW)
Note: NOx based on Rule 1110.2, CO and VOC from SCR & CatOx equipped source tests, PMfrom AP-42.
Figure 18. Emissions vs. capacity for reciprocating engines.
GHG
The greenhouse gas emission factor for methane, summarized in Table 15, is the average of
source tests from (Mintz, Han et al. 2010) and (SCS 2007). This is a methane destruction
efficiency of 98%. The CO2 emission factor is calculated assuming stoichiometric combustion of
biogas (60% methane). The CO2 emissions are biogenic. The N2O emission factor is from
(Mintz, Han et al. 2010), a life-cycle analysis of landfill gas based energy pathways.
Table 15. GHG emission factors - reciprocating engines.
GHG Emission Factors (Ib/MMBtu)
ch4
CO2
N20
0.838
191.3
0.00192
Output-based GHG emissions (lb CCheq/MWh) for engines (Table 16) are estimated using the
emission factors in Table 15, conversion efficiencies (from Table 13) and respective GWP100.29
CO
NOx
VOC
PM
29 GWPioo= 34, 298 and 1 for CH4, N20, and CO2, respectively.
22
-------
Table 16. Output based GHG emissions- reciprocating engines.
Greenhouse Gases
kW
(lb C02eq/MWh)
ch4
C02
N20
100
408
2,740
8.2
150
382
2,560
7.7
190
368
2,470
7.4
220
360
2,420
7.2
300
345
2,310
6.9
420
329
2,210
6.6
600
314
2,110
6.3
800
303
2,030
6.1
1000
295
1,980
5.9
1550
280
1,880
5.6
2000
272
1,830
5.5
3000
261
1,750
5.2
*Biogenic CO2 emissions
Cost
Installed cost for reciprocating engines ranges from $4,114/kW for the 100 kW size to about
$2,289/kW for 3,000 kW (Table 17). Estimated LCOE ranges from $90/MWh to $48/MWh for
the capacities reviewed (Table 17 and Figure 19).
23
-------
Table 17. Reciprocating engine cost analysis and LCOE.
Capacity
(kW)
Electricity
Production
(MWh/y)a
Component Costs
Total Capital
Annual
Debt &
Interest
($)e
Capital
Cost
($/kWh)
O&M
(engine
&
emiss.)
$/kWh)f
Clean up
O&M
($/kWh)g
LCOE
($/kWh)
Engine
system
($/kW)b
Gas
Cleanup
($/kW)c
Emissions
Reduction
($/kW)d
($/kW)
Total
Installed
($)
100
745
3,100
340
672
4110
411,000
35,800
0.048
0.030
0.012
0.090
150
1,120
2,970
340
574
3880
582,000
50,700
0.045
0.028
0.009
0.083
190
1,410
2,890
340
523
3750
713,000
62,100
0.044
0.028
0.008
0.079
220
1,640
2,840
340
494
3670
807,000
70,400
0.043
0.027
0.007
0.077
300
2,230
2,740
340
438
3520
1,060,000
92,100
0.041
0.026
0.006
0.073
420
3,130
2,620
340
384
3340
1,400,000
122,000
0.039
0.025
0.005
0.069
600
4,470
2,510
340
334
3180
1,910,000
166,000
0.037
0.024
0.004
0.065
800
5,960
2,410
340
299
3050
2,440,000
213,000
0.036
0.023
0.003
0.062
1000
7,450
2,340
293
274
2910
2,910,000
254,000
0.034
0.023
0.003
0.059
1550
11,500
2,190
219
231
2640
4,090,000
357,000
0.031
0.021
0.002
0.054
2000
14,900
2,100
184
209
2490
4,980,000
434,000
0.029
0.021
0.002
0.052
3000
22,300
1,970
141
178
2290
6,870,000
599,000
0.027
0.019
0.001
0.048
Sources and Notes:
a. At 85% capacity factor.
b. Basic Installed Cost (no gas cleaning, no after treatment). ICF 2012, Darrow, K., R. Tidball, J. Wang and A.
Hampson (2015). Catalog of CHP Technologies. ICF, EPA CHP Partnership. Using this curve fit: $/kW = -
332.91n(x) + 4635.
c. Cleanup Cap Cost - siloxane removal curve fit 35064 X"375, Figure 11 from: GTI (2014). (GTI Study, then
constant at 340 for < 200 scfm).
d. After treatment cost ($/kW) (Hybrid 2gCenergy & ICF 2012 data).
e. 20 years 'a. 6% annual interest rate (or cost of money).
f. EPA 2012 x 1.25 for after treatment.
g. Cleanup O&M Cost - siloxane removal curve fit 2047X" 3988, Figure 12 from: GTI (2014). Op. Cit.
0.10
0.08
0.06
LCOE - Reciprocating Engines
2*
1
S °°4
0.02
0.00
[
1 500 1000 1500 2000 2500 3000
Capacity (kW)
Figure 19. LCOE for reciprocating engines.
24
-------
Fuel Cell
Fuel cells produce direct current power through an electrochemical process, rather than a
combustion-to-mechanical energy process that turns an electrical generator. This electrochemical
process also generates far lower criteria pollutant emissions, which in some cases are considered
to be zero.
Stationary fuel cells that operate on natural gas or biogas are usually the high temperature
"internal reforming" type which includes molten carbonate fuel cells (MCFC) and solid oxide
fuel cells (SOFC). Because of the high internal temperature, MCFC and SOFC fuel cells can
internally reform methane with steam to produce the hydrogen necessary for the electrochemical
reaction (Figure 20).
Hydrocarbon Fuel
STEAM
INTERNAL REFORMING
CH4 + 2H20~ 4H: + CO:
CATALYST
ELECTROLYTE
AIR
Adapted from: http://wwwJueIceUenergy.com/
Figure 20. Schematic - internal reforming molten-carbonate fuel cell.
There are some 400 stationary fuel cells in California for a total installed capacity of
approximately 180 MW (SelfgenCa 2015). Eleven are fueled by biogas (installed capacity of ~
10 MW) (ORNL 2015, SelfgenCa 2015).
The company FuelCell Energy is active in the biogas fuel cell market in California, offering 300
kW, 1.4 MW, 2.8 MW and larger units. Bloom, Doosan, LG Fuel Cell Systems, and GE also
offer stationary fuel cell products that work with natural gas or extensively pre-treated and
cleaned biogas.
25
-------
Efficiency
Electrical conversion for internal-reforming fuel cells ranges from 42-54% net, HHV basis
(Trendewicz and Braun 2013, FuelCell_Energy 2015, ICF 2015). For this analysis, 45%
efficiency is used. Table 18 displays gas input flow (volume and energy basis) for a range of fuel
cell capacities.
Table 18. Fuel cell capacities and associated biogas input flows.
Capacity (kW)
Biogas Flow input*
(SCFM)
(MMBtu/h)
200
42
1.5
300
63
2.3
500
110
3.8
800
170
6.1
1000
210
7.6
1400
290
10.6
6000
1260
45.5
*Assumes 60% methane in biogas
Emissions
Criteria Pollutants & GHG
One of the most attractive features of fuel cells is that they have extremely low emissions. Those
emissions come from the combustion or oxidation of the anode off gas which contains unreacted
hydrogen, CO and VOCs. Catalytic or surface burners are usually used for the anode off gas,
which operates at high enough temperature to oxidize the hydrogen (Fh), CO, and VOCs while
producing very low NOx emissions (ICF 2015).
Emission factors for fuel cells are derived from review of two permits, both for FuelCell Energy
systems, one in the SJVAPCD and the other in the SCAQMD. The higher of the two permit
levels was used for each criteria pollutant in Table 19.
GHG emissions and emission factors are also displayed in Table 19. The emission factors
(lb/MMBtu) forN20 and CH4 are derived from IPCC guidelines (IPCC 2006). The CO2
emission factor is calculated assuming stoichiometric oxidation of biogas (60% methane). The
CO2 emissions are biogenic.
Table 19. Criteria pollutant and GHG emissions from fuel cells.
Emissions
Criteria Pollutants
NOx
CO
PM
voc
SOx
(Ib/MWh)
0.02
0.070
0.01
0.06
0.001
(lb/MMBtu)
0.0026
0.0092
0.0013
0.008
0.0001
(lb C02eq/MWh)
n/a
GHG
ch4
C02*
NzO
0.019
1450
0.002
0.0026
191.3
0.00026
0.66
1450
0.58
*biogenic CO2 emissions
26
-------
Cost
Cost information for biogas fuel cells is derived from a number of sources including:
(Trendewicz and Braun 2013) which modeled techno-economic performance of biogas
SOFC fuel cells in California wastewater treatment facilities,
(Horn 2013), a United States Court of Federal Claims opinion which examined project
costs for the Anaergia fuel cell at the Inland Empire Utilities Agency (IEUA) Water
Recycling Facility (RP-1) in Ontario, California,
(USEPA 2013) describing a fuel cell project at the Palmdale Water Reclamation Plant in
LA County, and
(FuelCells.org 2011), a case study on multiple fuel cells installed at the Tulare WRRF.
The installed costs analyzed here include gas cleaning equipment, engineering,
permitting, etc.
Installed costs for fuel cells are high, ranging from nearly $8,000/kW (250 - 300 kW size) to
about $3,800/kW (6,140 kW size) (see Table 20). A curve was fit through the literature costs
(using year 2015 $), used to model costs for analysis in this report (see note 5 below Table 20).
Table 20. Fuel cell capital costs from literature.
Literature Source
kW
Installed Cost ($/kW) [yr. 2015 $]
Literature value
Curve-fit Value5
Trendewicz1
330
6,261
6,990
Trendewicz1
1530
4,239
5,020
Trendewicz1
6140
3,879
3,720
Anaergia2
1400
5,714
5,120
EPA Fact Sheet3
250
7,600
7,430
Tulare4
300
7,967
7,140
Sources and Note:
1. Trendewicz, A. A. and R. J. Braun (2013). "Techno-economic analysis of solid oxide fuel cell-based on CHP
systems for biogas utilization at wastewater treatment. (Trendewicz and Braun 2013).
2. Horn (2015). Anaergia - RP1 Fuel Cell LLC et al v. USA. Reported Opinion, Judge Marian Blank Horn.
2013cv00552, United States Court of Federal Claims. (Horn 2013).
3. U.S. EPA (2013). Renewable Energy Fact Sheet: Fuel Cells.
http ://nepis. epa. gov/Exe/ZvPURL. cgi?Dockev=P 100IL86. txt (USEPA 2013).
4. FuelCells.Org (2011). Case Study: Fuel Cell System Turns Waste into Electricity at the Tulare Wastewater
Treatment Plant. http://www.fuelcells.org/uploads/TulareCaseStudv.pdf (FuelCells.org 2011).
5. Derived curve fit is: Installed Cost ($/kW) = 24475x"°216, where x capacity in kW.
The O&M costs are based on a $500k per year maintenance contract for a 1,400 kW MCFC
which includes five-year stack replacement (Remick and Wheeler 2010). Linear scaling
(extrapolation) was used to adjust O&M costs (maintenance contract) for other capacities in the
analysis. LCOE for biogas fuel cells varies from $0.164/kWh for the 200 kW size to $0.079/kWh
for 6,000 kW (Table 21 & Figure 21).
27
-------
Table 21. Fuel cell cost analysis and LCOE.
Capacity
(kW)
Electricity
Production
(MWh/y)a
Instal
ed Cost
Annual Debt
& Interest
($)b
Cap
Cost
($/kWh)
O&M Cost
($/kWh)c
LCOE
($/kWh)
($/kW)
Total
Installed ($)
200
1.5
7,790
1,560,000
136,000
0.091
0.073
0.164
300
2.2
7,140
2,140,000
187,000
0.084
0.067
0.150
500
3.7
6,390
3,200,000
279,000
0.075
0.060
0.135
800
6.0
5,780
4,620,000
403,000
0.068
0.054
0.122
1000
7.4
5,500
5,500,000
480,000
0.064
0.052
0.116
1400
10.4
5,120
7,170,000
625,000
0.060
0.048
0.108
2800
20.8
4,410
12,300,000
1,070,000
0.052
0.041
0.093
6000
44.7
3,740
22,400,000
1,950,000
0.044
0.035
0.079
Sources and Notes:
a. At 85% capacity factor.
b. 20 years 'a. 6% annual interest rate (or cost of money).
c. Based on a $500k/y maintenance contract for a 1,400 kW MCFC that includes five-year stack replacement.
Assumed linear scaling for other capacities. From: Remick, R. and D. Wheeler (2010). Molten Carbonate and
Phosphoric Acid Stationary Fuel Cells: Overview and Gap Analysis. NREL/TP-560-49072L.
LCOE - Fuel Cell
0.18
0.16
0.14
0.12
0.10
2 0.08
w
0.06
0.04
0.02
0.00
200 300 500 800 1000 1400 2800
Capacity (kW)
Figure 21. LCOE - fuel cell.
Compressed RNG (on-site fuel)
Biogas can be cleaned and upgraded to be suitable for a vehicle fuel, such as CNG or Liquefied
Natural Gas (LNG). For this biogas use pathway, we only looked at renewable CNG, but not
LNG (even though we realize that LNG is being used at some biogas facilities, like the Waste
Management project at the Altamont Landfill)30. Renewable CNG pathway cost and
311 For those interested in the Altamont LF LNG project: http://altamontlandfill.wm.com/green-energy/index.jsp
28
-------
performance analysis is based on Unison Solutions (BioCNG) upgrading and fueling station for
biogas input flows of 50-200 scfm and a large system (1,600 scfm biogas input) consisting of a
Unison Solutions H2S removal system, a Guild pressure swing adsorption (PSA) separation unit
and an ANGI CNG fueling station.
Efficiency
The Unison Solutions' (BioCNG) equipment is installed at several sites in California, including
the CleanWorld digester facility at Sacramento and the Blue Line RNG facility in South San
Francisco. The equipment for the smaller capacity system uses a single-pass membrane
technology for CO2/CH4 separation. About 70% of incoming methane is upgraded to fuel with
the rest exiting the system with the CO in the tailgas (Figure 22) (BioCNG 2015).
The larger capacity system consisting of the Guild PSA system has a higher methane recovery
rate of 85% or higher (Santos, Grande et al. 2011, Wu, Zhang et al. 2015). This analysis uses
70% recovery rate for systems < 200 scfm biogas input (BioCNG model) and 85% methane
recovery for the large facility (1600 scfm) (Figure 22 and Table 22).
The tailgas cannot be vented (i.e. released untreated into the atmosphere). It can possibly be
burned in an engine. This analysis assumes it is burned in a flare.
BIOGAS INPUT
(CH4 & CO2, moisture,
contaminants)
Tail Gas:
15-30% of CH4, -93-94% of CO2
A
Cleaning,
Separating,
Compressing
Compressed RNG
(fuel product)
of CH4 (~95% CH4> 50/0 c°2>
moisture, contaminants)
70-85%
>
Figure 22. RNG process schematic.
Simple volume and energy flows for representative systems are tabulated below (Table 22).
Table 22. RNG input and output flow and energy.
Biogas Flow input
Methane
recovery
[%)
RNG Fuel Product Output
(SCFM)
(MMBtu/h)
(SCFM)
(MMBtu/h)
(GGE/day)
50
1.8
70
22.1
1.3
241
100
3.6
70
44
2.5
482
200
7.2
70
88
5
963
1600
57.6
85
860
49
9,360
29
-------
Emissions
Criteria Pollutants
An important feature of biogas upgrading for RNG fuel or pipeline injection is that on-site
criteria pollutant emissions can be much lower than some of the combustion-based engines.
Criteria pollutants will occur when and where the product gas is used in amounts that depend on
those ultimate uses, such as vehicle emissions, natural gas power plants, in-home gas appliances,
etc.
For the RNG pathway analyzed here, only on-site criteria pollutants are evaluated. The RNG
upgrading process creates a tailgas (or byproduct gas) that contains a portion of the methane
input to the process (Figure 23). Because the methane is a significant GHG if discharged into the
atmosphere, the tailgas must be processed to reduce or eliminate the unrecovered or byproduct
methane.
t
1% Leakage
(CH4 & CO2)
w
ZJ
u
E
Flare Emissions
(NOx, CO, VOC, SOx,
PM, CH4. CO2. N2O)
^ Tail Gas-to Flare
CO2 & 15-30% of CH4
BIOGAS INPUT
Cleaning,
Separating,
Compressing
70-85% Compressed RNG
of CH4 (fuel product)
Figure 23. RNG process schematic with tailgas flare.
It may be possible in certain cases to burn the tailgas in an engine or turbine as a primary or co-
fired fuel input which will oxidize the methane to CO2. This analysis assumes the tailgas is
burned in a flare for purposes of methane destruction (Figure 23). Emissions for tailgas burned in
a flare are tabulated below (Table 23) and are based on the same flare emission factors discussed
in the flare section.
30
-------
Table 23. RNG on-site criteria pollutant emissions.
Biogas Flow input
Methane
recovery
(%)*
RNG Fuel
Product
Output
Emissions (lb/day)*
(SCFM)
(MMBtu/h)
(MMBtu/h)
NOx
CO
PM
VOC
SOx
50
1.8
70
1.3
0.71
0.59
0.15
0.08
0.50
100
3.6
70
2.5
1.43
1.18
0.31
0.16
1.01
200
7.2
70
5
2.86
2.36
0.62
0.31
2.02
1600
57.6
85
49
11.04
9.13
2.39
1.21
7.79
Emission Factor (lb/MMBtu input to process)
70% Methane Recovery
0.0165
0.0137
0.0036
0.0018
0.0117
85% Methane Recovery
0.008
0.007
0.002
0.001
0.006
{Methane recovery = Yield or the portion of incoming methane that is recovered in the product. The unrecovered methane exits
the upgrade process in the tailgas and is assumed burned in a flare in this analysis.
*Based on flare emission factors of 0.057, 0.0472, 0.01236, 0.0062 and 0.0403 lb/MMBtu forNOx, CO, PM, VOC and SOx
respectively (See Flare section).
GHG
GHG emission factors include assumed 1% methane (biogas) leakage from the upgrading
process (Han, Mintz et al. 2011)31, methane slip through the tailgas flare and N2O emissions
from the flare (Mintz, Han et al. 2010). The CO2 emission factor includes that in the incoming
biogas that is separated from the methane in the upgrading process and then passes through the
flare plus the product of methane combustion from tailgas burned in the flare as well as the small
amount in the 1% leakage assumption mentioned above. The CO2 emissions are biogenic (Table
24 and Figure 23).
Table 24. RNG process GHG emissions.
Gas Flow Input to
RNG Svstem
Greenhouse Gases (ib/day)
Greenhouse Gases
(lb CC>2eq/day)
ch4
C02*
NzO
ch4
C02*
NzO
(SCFM)
(MMBtu/h)
50
1.8
18.9
4,600
0.03
642
4,600
9
100
3.6
37.8
9,200
0.06
1,280
9,200
18
200
7.2
75.5
18,400
0.12
2,570
18,400
36
1600
57.6
590
122,000
0.47
20,100
122,000
140
(lb/MMBtu into process)
ch4
C02*
NzO
GWP100
70% CH4 Recovery
0.44
106.5
0.00070
ch4
C02*
NzO
85% CH4 Recovery
0.43
88.3
0.00034
34
1
298
*Biogenic C02 emissions
31 1% methane leakage from the upgrading process is a default assumption used by GREET in Han, Mintz et al.
(2011). [An Argonne National Lab report]
31
-------
Cost
RNG pathway costs are estimated using installed capital and operating costs and methane
recovery efficiency derived from BioCNG project information and consultant reports (Geosyntec
2013, BioCNG 2015, Kemp 2015, Polo 2015). Cost of capital is based on 20-year capital loans at
6% annual interest and includes fuel dispensing equipment and nominal gas storage
(approximately half to one day of gas storage). RNG production cost is estimated to vary from
about $2.42 per GGE [$18.30/MMBtu] at small scale to about $0.50/GGE [$4.00/MMBtu] at
large scale (Table 25 and Figure 24).
Table 25. RNG costs.
Input-
(scfm
biogas)2
Fuel Output
RNG
Equipment
Cost
(MM $)1
Flare
Cost
($)3
Total
Capital
($)
Annualized
Capital
($/y)4
O&M
CNG
($/GGE)1
CNG O&M
(S/y)
O&M (CNG
+ Flare)
(S/y)
$/GGE
$/MMBtu
(output)
RNG
(scfm,
95%
CH4)
GGE/day
GGE/year
50
22.1
240
83,500
1.2
69,800
1,270,000
111,000
1.06
88,000
91,000
$2.42
$18.30
100
44.2
480
167,000
1.5
116,000
1,620,000
141,000
0.82
137.000
142,000
$1.69
$12.79
200
88.4
960
334,000
2.0
192,000
2,190,000
191,000
0.64
214,000
221,000
$1.23
$9.34
1600
860
9400
3,250,000
6.54
511,000
7,050,000
615,000
0.34
1,090,000
1,110,000
$0.53
$4.02
Sources and Notes:
1. Based on BioCNG project sheets, conference presentations, Geosyntec report to Flagstaff Landfill and personal
communication, Jay Kemp and Christine Polo, Black and Veatch. 70% methane recovery for single-pass membrane
system (BioCNG 50-200 scfm input) and 85% methane recovery for PSA system (1600 scfm input).
2. 60% methane inbiogas.
3. Tailgas (methane slip) is flared in this scenario. Added flare capital and operating costs using data from flare
scenario.
4. 6% APR, 20-year financing of capital - $0.12/kWh electricity cost.
$3.00
_ $2-50
OJ
00
$2.00
$1.50
$1.00
$0.50
$0.00
$/gge Cost Estimate
y = 3.0156X0434
R2 = 0.9974
10 20 30 40
Biogas Input (MMBtu/h)
50
60
$21
g
Q.
g
$18
O
s
CO
$15
5
$12
"K
$9
u
c
o
$6
'¦M
s
"C
$3
o
O.
$0
$/MMBtu Output
y = 22.754X 0 432
R2 = 0.9972
10 20 30 40
Biogas Input (MMBtu/h)
50
60
Figure 24. RNG production cost estimates.
32
-------
Upgrade & Pipeline Injection
Biogas can be upgraded and then injected into the pipeline. Upgrading to pipeline quality RNG
involves cleaning the raw biogas (remove sulfur, siloxane, usually water vapor), separating the
methane from the carbon dioxide and delivering a product that meets the local gas utility gas
standard or tariff32 There are more than eighty biogas upgrading to pipeline injection facilities in
Europe (IEA 2015). In the U.S., there are approximately fifty such facilities, including landfills
and WRRFs (Escudero 2016). In California, there is one: at the Point Loma Water Resource
Recovery Facility.
There are a variety of technologies available to upgrade biogas (separating CO2 from methane)
including (Ryckebosch, Drouillon et al. 2011, IEA 2014):
physical/chemical absorption (water or amine scrubbers) [~ 65% of systems in Europe]
permeable membrane systems [11% of systems in Europe]
adsorption (i.e., pressure swing adsorption) [23% of systems in Europe]
BioFuels Energy, LLC is upgrading digester gas from the Point Loma Water Resource Recovery
Facility near San Diego. It uses a two-stage permeable membrane system provided by Air
Liquide (Figure 25) which recovers about 85-87% of input methane (Frisbie 2015).
VOCs, CO2 to Flare
Membrane
2nd Stage
Booster
From Landfill Membrane
or Biogas Compressor Regenerable Carbon 1st Stase
Collection 16 bar a VOC Removal Filter .
T
± CO2 Rich
,,,,,, __ Permeate
Gas to
Pipeline
Permeate Recycle
Adapted from Air Liquid: http://www.medal.airliquide.com/enfbiogaz-systems.html
Figure 25. Schematic - two-stage-membrane upgrade system.
32 For example, see Southern California Gas Company, Rule 30 "Transportation of Customer-Owned Gas"
https://www.socalgas.com/regulatorv/tariffs/tm2/pdf/30.pdf.
33
-------
Efficiency
Achievable methane recovery or yield for commercially available upgrading technologies is
reported to be in the 96-99% range (Petersson and Wellinger 2009, Ryckebosch, Drouillon et al.
2011, Bauer, Hulteberg et al. 2013, IEA 2014). Methane recovery for the BioFuels Energy, LLC
facility at Point Loma, California is reported to be 85-87% (Frisbie 2015). For upgrading to
biomethane for pipeline injection in this analysis, a 90% methane recovery is used.
Basic volume and energy flows for a range of biogas upgrade-to-pipeline-injection capacities are
tabulated below (Table 26). Methane concentration (or content) in the product gas is 98% in
order to meet the required heating value (990 Btu ft"3) for pipeline gas.33
Table 26. Upgrade-to-pipeline-injection input and product yield.
Biogas Flow Input
Product Gas Flow*
(SCFM)
(MMBtu/h)
(SCFM)
(MMBtu/h)
50
1.8
27.5
1.6
75
2.7
41
2.4
100
3.6
55
3.2
150
5.4
83
4.9
300
10.8
165
9.7
600
21.6
331
19.4
1200
43.2
661
38.9
2300
82.8
1267
74.5
*Assumes 90% methane yield and 98% methane content in product gas (990 Btu ft"3, HHV)
Emissions
Criteria Pollutants
On-site criteria pollutant emissions for biogas upgrading for RNG fuel or pipeline injection are
relatively low because most of the methane is moved off-site and used (burned) elsewhere.
Depending on where the product methane is used, such as at high efficient central station power
production or in low-emission CNG vehicles, total emissions (on-site plus off-site) can be lower
than most stationary engines, some turbine applications or flaring.
For the upgrading-to-pipeline-injection pathway analyzed here, only on-site criteria pollutants
are evaluated. These consist of flare emissions from burning the tailgas to destroy process
methane slip (Figure 26).
33 "Recovery rate" and "methane content in product gas". Recovery rate describes how much of the methane in the
incoming biogas is turned into product ("yield" could be used here as well). Methane content in final product is
simply a concentration value, or physical property of final product.
34
-------
t
1 % Leakage
(CH4 & CO2)
w
0>
CQ
E
1
1
Flare Emissions
(NOx, CO, VOC, SOx,
PM, CH4. CO2. N2O)
Tail Gas-to Flare
10% of CH4
BIOGAS INPUT
Cleaning,
Separating,
Compressing
90%
of CH4
Compressed &
> Injected to Pipeline
(-98% CH4.2% CO2)
Figure 26. Upgrade-to-pipeline process schematic with tailgas flare.
Emissions for tailgas burned in a flare are tabulated below (Table 27) and are based on the same
flare emission factors discussed in the flare section below.
Table 27. Upgrade-to-pipeline injection on-site criteria pollutant emissions.
Biogas Flow Input
Product Gas
Flow
Emissions* (lb/day)
(SCFM)
(MMBtu/h)
(MMBtu/h)
NOx
CO
PM
VOC
sox
50
1.8
1,6
0.22
0.18
0.05
0.02
0.16
75
2.7
2.4
0.33
0.28
0.07
0.04
0.23
100
3.6
3.2
0.44
0.37
0.10
0.05
0.31
150
5.4
4.9
0.67
0.55
0.14
0.07
0.47
300
10.8
9.7
1.3
1.1
0.3
0.1
0.9
600
21.6
19.4
2.7
2.2
0.6
0.3
1.9
1200
43.2
38.9
5.3
4.4
1.2
0.6
3.8
2300
82.8
74.5
10.2
8.4
2.2
1.1
7.2
Emission Factor (lb/MMBtu input to process)
0.0051
0.0042
0.0011
0.0006
0.0036
*Based on flare emission factors of 0.057, 0.0472, 0.01236,0.0062 and 0.0403 lb/MMBtu for NOx, CO. PM, VOC
and SOx respectively. (See Flare section.)
GHG
GHG emission factors include 1% methane (biogas) leakage from the upgrading process (Flan,
Mintz et al. 2011), methane slip through the tailgas flare and N2O emission from the flare
35
-------
(Mintz, Han et al. 2010). The CO2 emission factor includes that in the incoming biogas that is
separated from the methane in the upgrading process and then passes through the flare plus the
product of methane combustion from tailgas burned in the flare as well as the small amount in
the 1% leakage assumption mentioned above. The CO2 emissions are biogenic (Table 28 and
Figure 26).
Table 28. Upgrade-to-pipeline-injection process GHG emissions.
Biogas Flow Input
Greenhouse Gases (lb/day)
Greenhouse Gas
(lb C02eq/day
es
(SCFM)
(MMBtu/h)
ch4
C02*
NzO
ch4
C02*
NzO
50
1.8
18.8
3,720
0.009
640
3,720
3
75
2.7
28.2
5,580
0.014
960
5,580
4
100
3.6
37.7
7,440
0.019
1,280
7,440
6
150
5.4
56.5
11,200
0.028
1,920
11,200
8
S300
10.8
113
22,300
0.057
3,840
22,300
17
600
21.6
226
44,700
0.113
7,680
44,700
34
1200
43.2
452
89,300
0.226
15,400
89,300
67
2300
82.8
866
171,000
0.434
29,400
171,000
129
(Ib/MMBtu input to process)
GWP100
ch4
C02*
NzO
ch4
C02*
NzO
0.4358
86.1
0.00022
34
1
298
*Biogenic CO2 emissions
Cost
Because there are so few operating facilities (one known in California), biogas upgrading and
injection costs are derived from a consultant report that modeled these costs as part of a financial
evaluation of an RNG program proposed for gas utilities in Ontario, Canada (Electrigaz 2011).
For the purposes of this study, the Electrigaz analysis was updated to year 2015 U.S. dollars with
injection (i.e., interconnection) capital and O&M also modified to reflect expected higher costs
in California (Table 29).
Table 29 shows installed capital and O&M costs for four project sizes (2.6, 9.2, 21.5 and 72.3
MMBtu/h product output).34 Capital costs were annualized over a 20-year project life at 6%
annual interest (or cost of money). Based on an evaluation of industry comments submitted to
California Public Utilities Commission (CPUC) Proceeding R1302008, interconnect capital
expenditure (CAPEX) and operations expenditure (OPEX) multipliers are 1.7 and 8,
respectively. These were applied to the Electrigaz interconnect values (increases of ~$l-3 million
34 These are the capacities analyzed in the Electrigaz study.
36
-------
CAPEX and $50-100k OPEX).35 Note that even with these interconnection cost increases, the
upgrading portion still dominates at 75-90% of total production cost (Table 29).
Table 29. Upgrade and injection cost modeling.
Input Flow (SCFM, 60% CH4)
72.7
265.6
621.5
2071.0
Product Methane (SCFM)
42.8
151.7
355.0
1192.9
Product Methane (MMBtu/h)
2.6
9.2
21.5
72.3
Upgrading Installed Capital
2,180,000
4,860,000
8,460,000
13,500,000
Injection, piping, compression*
(includes the 1.7x California Multiplier)
968,000
1,260,000
2,710,000
3,500,000
Total Capital
3,148,000
6,120,000
11,170,000
17,000,000
[20-year amortization, 6% interest]
Upgrading Capital (annualized, $/y))
Injection Capital (annualized, $/y)
190,000
84,400
424,000
110,000
738,000
236,000
1,177,000
305,000
Annual Capital Expense ($/y)
O&M - Upgrading ($/y)
274,400
218,200
534,000
619,100
974,000
1,185,000
1,480,000
3,222,000
O&M - Injection ($/y)**
(**includes the 8x California Multiplier)
41,100
48,700
108,300
113,700
Annual ($/Y)
533,700
1,202,000
2,267,000
4,816,000
Upgrading Cost ($/MMBtu)
Injection Cost ($/MMBtu)
17.98
5.52
12.95
1.97
10.20
1.83
6.95
0.66
Total Production Cost ($/MMBtu)
23.50
14.92
12.03
7.61
Notes:
Base upgrading and injection costs derived from: Electrigaz (2011). Biogas plant costing report: Economic Study on
Renewable Natural Gas Production and Injection Costs in the Natural Gas Distribution Grid in Ontario, Prepared for
Union Gas.
California injection CAPEX and OPEX "Multipliers" from industry comments to CPUC Proceeding R1302008 -
Order Instituting Rulemaking to Adopt Biomethane Standards and Requirements.
Figure 27 displays cost curves derived from the Electrigaz study (Electrigaz 2011) including a
curve estimating costs for meeting California pipeline and interconnection standards (curve
labeled "Electrigaz study w/ California adder" in the figure). Also shown for comparison
purposes are:
35 CPUC Proceeding R1302008 - Order Instituting Rulemaking to Adopt Biomethane Standards and Requirements,
pipeline Open Access Rules, and Related Enforcement Provisions. Presiding Commissioner: Carla Petennan:
http://delapsl.cpuc.ca.gov/CPUCProceed.ingT ,ookiro/f?p=401:56:7166425933242::NO:RP.57.RIR:P5 PROCEEDIN
G SELECT:R1302008
37
-------
Two existing projects: a landfill-gas-to-pipeline-injection project in Texas (Williams 2015)
and BioFuels Energy, LLC facility at the Point Loma Water Resource Recovery Facility
(Frisbie 2015);
Proposed upgrading and injection facility at Los Angeles County Sanitation Districts
(Boehmke 2015); and
Estimated high and low cost estimate in Waste Management comments to CPUC
(Waste_Management 2014).
W
l/>
O
u
c
o
u
cu
B 10
c
o3
aj
-a
i
t>0
Q.
D
25
20
15
Upgrading & Injection Cost
._ ^ n 33/1 1
[ *\ V =
: V f
\\
\\
3Z.1/HX
I2 = 0.9961
Electrigaz study w/ California Adder
i Electrigaz study
~ Point Loma - approx.
¦ LFG-to-pipeline - Texas project
>
I »
< LA County Sanitation District
~ WM hi - lo: CPUC comments
1 *»»
y = 27.525x0308 -
R2 = 0.998
~
~
Sources & notes:
- Electrigaz (2011). Biogas plant costing report: Economic Study on Renewable Natural Gas Production
Costs in the Natural Gas Distribution Grid in Ontario, Prepared for Union Gas .
-Comments to CPUC biomethane proceedings used to model CA interconnection using multipliers.
-Developer conversations
and Injection
20
40 60 80
Biomethane Flow (MMBtu/h)
100
120
Figure 27. Upgrade and injection cost vs. capacity.
Flare
Flaring biogas without energy recovery is one method for disposing both methane and VOCs by
burning and converting the vast majority of these emissions to CO2. Flaring is assumed to be a
default biogas application when intentional discharge or venting of biogas into the atmosphere is
prohibited.
Criteria pollutant emission factors appear in the lower portion of Table 30 and are derived from
weighted average source test emissions from three digester gas flares and one landfill gas flare
(SCAQMD and SJVAPCD). (See Appendix C.) Criteria pollutant mass flows (lb/day) are also
estimated in Table 30 for a range of flow rates. Emission factors for N2O and CFL are taken from
(Mintz, Han et al. 2010).
38
-------
Table 30. Flare emissions and emission factors.
Gas Flow
Emissions (lb/day)
Greenhouse Gases
Input
NOx
CO
PM
voc
SOx
Greenhouse Gases
(lb C02eq/day)
(MMBtu/h)
CH4
CO2*
N2O
CH4
CO2*
N2O
0.6
0.82
0.68
0.18
0.090
0.58
1.0
2,760
0.03
34
2,760
10.4
1
1.37
1.13
0.30
0.150
0.97
1.7
4,590
0.06
57
4,590
17.3
2
2.74
2.26
0.59
0.300
1.93
3.3
9,180
0.12
114
9,180
34.7
5
6.85
5.66
1.48
0.749
4.83
8.4
23,000
0.29
284
23,000
86.7
7
9.58
7.92
2.08
1.049
6.76
11.7
32,100
0.41
398
32,100
121
10
13.7
11.3
2.97
1.499
9.66
16.7
45,900
0.58
568
45,900
173
15
20.5
17.0
4.45
2.248
14.49
25.1
68,900
0.87
853
68,900
260
20
27.4
22.6
5.93
2.998
19.32
33.4
91,800
1.16
1,140
91,800
347
30
41.1
34.0
8.90
4.496
28.98
50.2
138,000
1.75
1,710
138,000
520
Emission Factor (Ib/MMBtu)
Emission Fact
(Ib/MMBtu
or
NOx
CO
PM
VOC
SOx
ch4
CO2*
N2O
GWP100
0.057
0.047
0.0123
0.0062
0.0403
0.07
191.3
0.0024
34
1
298
*Biogenic CO2 emissions
Cost
Flare costs are derived from (ICF 2013) with an estimated gas disposal cost of about
$1.25/MMBtu at small scale to less than $0.50/MMBtu at the largest flow size as shown in Table
31.
Table 31. Flare gas disposal cost.
Gas Flow
Installed
Cost ($)
O&M
Cost ($/y)
Biogas
(SCFM)
MMBtu/h
17
0.6
51,700
2,070
28
1.0
75,800
3,030
56
2.0
128,000
5,120
140
5.0
254,000
10,200
190
7.0
326,000
13,000
280
10.0
426,000
17,000
420
15.0
578,000
23,100
560
20.0
717,000
28,700
830
30.0
972,000
38,900
Gas Disposal
Cost
($/MMBtu)
1.25
1.10
0.93
0.74
0.68
0.62
0.56
0.52
0.47
39
-------
3. Results and Discussion
Primary Technology Costs
Cost or revenue required to process biogas varies from less than $l/MMBtu (input flow basis)
for flare systems to $7-$25/MMBtu or more for upgrading the biogas for pipeline injection. Fuel
cell costs are similar to pipeline injection. Engines, microturbines and compressed RNG fuel
each fall below $5/MMBtu (input) for larger system sizes. Compressed RNG fuel processing is
above $10/MMBtu for small capacities. Combustion turbine costs are relatively flat ($3-
$4/MMBtu) (Figure 28). There are economies of scale for all processes investigated with fuel
cells, microturbines and gas upgrading to RNG or pipeline injection showing strong economies
of scale.
25
_ 20
4->
3
Q.
C
3 15
+-»
CO
5. io
vv
5
0
0 500 1000 1500 2000 2500
Biogas Flow (scfm)
Figure 28. Biogas processing costs.
The LCOE for fuel cells ranges from ~$0.16/kWh at small size to about $0.09/kWh at the 3 MW
size. Reciprocating engine LCOE varies from $0.09 to $0.05/kWh. Combustion turbines (gas
turbines) have the lowest LCOE of about $0.04/kWh at large scale (Figure 29).
Average California electricity prices for industrial and commercial customers [$0.123/kWh and
$0.156/kWh respectively (EIA 2016)], as well as the expected Bioenergy Feed-in Tariff price
floor (about $0.125/kWh), are shown on Figure 29 for comparison.
Upgrade-Pipeline Inject
Fuel Cells
RNG/CNG
Recip. Engines
Microturbines
Gas Turbines
Flare
40
-------
3
Q.
+¦>
3
O
u
u
_oj
-------
yv
LU
O
u
0.40
0.30
0.20
0.10
0.00
Existing Biogas
Full system (digester+ recip. engine)
Dairy Digester & Engine
This Report: Existing
Gas Recip Eng.
1000
3000
4000
2000
Capacity (kW)
Sources: Black and Veatch (2013). Small-Scale Bioenergy: Resource Potential, Costs, and
Feed-in Tariff Implementation Assessment, Prepared for the California Public Utilities
Commission. R. 11-05-005 AES/sbf/lil, and this report.
Figure 30. B&V LCOE estimates for biogas compared to this report.
Compressed RNG with on-site fueling varies from about $18/MMBtu produced (small scale) to
about $4/MMBtu at the largest size (or about $2.40 - $0.50 per gallon gasoline equivalent) and is
generally less costly than upgrading biogas for pipeline injection, which can be higher than
$25/MMBtu at small scale to about $7/MMBtu at very large scale (Figure 31).
Upgrade-to-Pipeline
Injection
RNG/CNG Fuel
1,000 1,500 2,000 2,500
Biogas Flow (scfm)
Figure 31. Biomethane product cost.
42
-------
Energy revenues from electricity sales are expected to be about $0.125/kWh based on the
Bioenergy Feed-in-Tariff "floor" or starting price.36 RNG must compete with the current low
natural gas prices and will require additional value offered by Low Carbon Fuel Standard
(LCFS) and Renewable Identification Number (RIN) credits for fuel applications or value from
other renewable attributes for RNG injected to the pipeline.
Criteria Pollutant Emissions
Criteria pollutant emission factors (lb/MMBtu gas input) are summarized in Table 32 and Figure
32. Reciprocating engines (even those based on Rule 1110.2 limits) have the highest NOx
emission factor among the on-site electricity prime movers. Flares have the highest average NOx
emission factor of all the analyzed applications (Figure 32). Fuel cells, followed by gas turbines
with SCR-based NOx control have the lowest NOx emission factors (for stationary power
applications).
The RNG fuel and pipeline injection pathways have emissions that occur both on-site and when
the gas is used elsewhere. The off-site mobile and stationary source emissions are beyond the
scope of this analysis.
Table 32. Emission factor comparisons: criteria pollutants.
Emission Factor (lb/MMBtu input)
[Source Test Averages, permit values, or AP-42]
NOx
CO
PM
voc
SOx
Reciprocating Engines
0.043
0.151
0.014
0.016
0.003
Micro-Turbines
0.016
0.017
0.001
0.008
0.067
Gas Turbines - Low NOx
0.031
0.004
0.012
0.007
0.063
Gas Turbines - SCR
0.011
0.013
0.012
0.0007
0.0046
Fuel Cells
0.003
0.009
0.001
0.008
0.0001
Upgrade to Pipeline
0.0051
0.0042
0.0011
0.0006
0.0036
RNG-CNG 70% Recovery
0.0165
0.0137
0.0036
0.0018
0.0117
RNG-CNG 85% Recovery
0.0080
0.0066
0.0017
0.0009
0.0056
Flare
0.057
0.047
0.012
0.006
0.040
Output-based criteria pollutants (lb/MWh) for the electricity producing systems appear in Figure
33 through Figure 35. For comparison, California central-station power plant best available
control technology (BACT) is also shown (CARB 2007).
36 CPUC Decision D. 15-09-004: http://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&DocID= 154488509
43
-------
0.08
3 0.06
CO
o 0.04
0.02
0.00
0.1- CO
NOx CO ¦ PM I VOC I SOx
.
I
¦ J I
I.
I.
Figure 32. Emission factors by technology.
1.00
NOx (Ibs/MWh); Note: log scales
I
Recip. Micro- Gas Turbines-Gas Turbines- Fuel Cells Upgrade to RNG-CNG RNG-CNG Flare
Engines Turbines Lo Nox SCR Pipeline 70% Recovery85% Recovery
_0J
ro
u
1/1
CUD
o
t/1
-Q
o.io
Reciprocating
Engines
Microturbines
Gas Turb. - Low
NOx.
Gas Turb. - SCR /
Ultra Low NOx
Fuel Cell
¦Central Station
Powerplant
0.01
10
100 1,000
Capacity (kW); log scale
10,000
Figure 33. NOx emissions (lb/MWh).
44
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10.00
CO (Ibs/MWh); Log scales
1.00
0.10
Reciprocating
Engines
Microturbines
Gas Turb. -Low
NOx
Gas Turb. - SCR-
UltraLow NOx
¦Fuel Cell
¦Central Station
Powerplant
0.01
10
100 1,000 10,000
Capacity (kW)
Figure 34. CO emissions (lb/MWh).
1.000
VOC (Ibs/MWh); Log scales
0.100
(/)
-Q
0.010
0.001
Reciprocating
Engines
Microturbines
Gas Turb. -Low
NOx
Gas Turb. - SCR-
UltraLow NOx
¦Fuel Cell
¦Central Station
Powerplant
10
100 1,000
Capacity (kW)
10,000
Figure 35. VOC emissions (lb/MWh).
45
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GHG Emissions
On-site GHG emission factors for conversion or processing are summarized for all systems in
Table 33 and Figure 36. Recall, upstream and downstream sources and sinks are beyond the
scope of this analysis.
All devices emit small but significant amounts of methane as "slip" (or unburned methane) from
conversion devices or through leaks in processing equipment, ranging from <1% to as much as
5% of the incoming methane in the fuel or biogas (CAR 2011), (Han, Mintz et al. 2011).
N2O emissions are generally taken from (IPCC 2006) and are rather small for these systems,
even when accounting for its large 100-year GWP of 278.
On-site CO2 emissions include those originally in the input biogas (40% CO2 content was used
for calculation purposes in this report) and those produced through the combustion of methane in
the conversion device. The CO2 emissions are biogenic.
Table 33. GHG emission factor summary.
Technology
GHG Emission Factor37
(Ib/MMBtu)
Notes
CH4
N2O
CO2
Recip. Engines
0.838
1.92E-03
191.3
Average of SCS (2007) & Mintz (ANL)*, N20 & ~ 97.99% CH4
destruction efficiency (2% slip)
Micro-Turbines
0.167
2.56E-04
191.3
Average SCS (2007) & CAR (2011): CH4 99.6% destruction efficiency,
N2O Emission Factor from Table 2.2 in 2006 IPCC Guidelines
Gas Turbines
0.167
2.56E-04
191.3
Average SCS (2007) & CAR (2011): CH4 99.6% destruction efficiency,
N2O Emission Factor from Table 2.2 in 2006 IPCC Guidelines
Fuel Cell
0.003
2.56E-04
191.3
Cm & N2O Emission Factor from 2006 IPCC Guidelines
Flare
0.07
2.43E-03
191.3
Mintz et al., (2010) CH4 99.8% destruction efficiency, N2O also from
Mintz (2010).
RNG/CNG
(70% recovery)
0.437
7.03E-04
106.5
1% CH4 leakage in upgrade process + flare emissions from tailgas
combustion. No vehicle or downstream combustion emissions
included.
RNG/CNG
(85% recovery)
0.427
3.40E-04
88.3
Upgrade-
Injection
0.436
2.18E-04
86.1
37 Units are lb/MWh of CH4, CO2 and N20. They are not displayed in (or converted to) CCheq.
46
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CH (Ib/MMBtu)
I
£ fa £ aN A .C
/ / / / ^ > / ¦/
J $ *& ^
$ / J
* $
/ / /
6+ J?
-f /
/ / ^
# #
V
-------
(CA eGRID factor is 0.006 lb N2O per MWh). Reciprocating engine N2O emissions are about
four times the California grid average (Figure 38).
10.00
Reciprocating Microturbines Gas Turbines Fuel Cells CA eGRID
Engines
Figure 37. Average methane emissions, bio-power technologies & CA eGRID.
0.100
0.010
0.001
Reciprocating Microturbines Gas Turbines Fuel Cells CA eGRID
Engines
Figure 38. Average N2O emissions, bio-power technologies & CA eGRID.
All the devices also emit significant amounts of CO2, resulting in overall CCheq emissions
factors that would appear higher than the CA eGRID factor of 653 lb CCheq per MWh output.38
38 eGRID uses GWP100 values from the IPCC Second Assessment Report (IPCC 1995). When applying the GWP100
from the Fifth Assessment Report (AR5 or IPCC 2013), the CA eGRID CChcq value increases by 0.05%.
48
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However, "eGRID assigns zero CO2 emissions to generation from the combustion of all biomass
(including biogas) because these organic materials would otherwise release CO2 (or other
greenhouse gases) to the atmosphere through decomposition" (USEPA 2015d). To compare to
eGRID's emission factor for CCheq, biogas CO2 emissions for the devices in this report are not
counted in the carbon intensity calculation. Therefore, the CCheq equivalent emission factors for
microturbines, gas turbines, reciprocating engines, and fuel cells are all considerably lower than
the CA eGRID factor of 653 lb CCheq per MWh output (Figure 39).
CO
800
600
400
200
2 eq.
Reciprocating Microturbines Gas Turbines Fuel Cells
Engines
\ss\
CA eGRID
Figure 39. CCheq emissions for the bio-power technologies & CA eGRID.
Additional Costs
Stationary Engines: Pre-Treatment
Before being combusted, biogas is typically "pre-treated" to remove water and other trace
contaminants. Depending on the biogas source and the emission requirements of the local air
district, additional treatment may be necessary. For example, biogas engines operating in the
SCAQMD will need to comply with Rule 1110.2, which restricts the NOx from stationary
engines to 11 ppm. By January 2017, biogas engine operators will have to invest in cleaner
technologies (e.g., fuel cells) or after-gas treatment technologies (e.g., SCR systems). As both are
highly sensitive to siloxanes and sulfur exposure can deactivate SCR catalysts in a matter of
hours facilities must additionally invest in treatments that can remove contaminants to a very
high degree. Sulfur treatment is a higher priority for fuel cells.
While the present analysis did not directly investigate such pretreatment costs, it used costs
estimated by a recent study sponsored by the SCAQMD. To help biogas facilities in their
jurisdiction comply with Rule 1110.2, the SCAQMD conducted a nationwide survey of biogas
cleanup technologies and costs (GTI2014). SCAQMD completed an extensive literature and
internet search to identify and obtain information on biogas cleanup systems, corroborated
49
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findings with vendor surveys, and compared the costs of various systems. Based on the findings,
SCAQMD developed an Excel-based calculation spreadsheet that estimates capital (equipment)
costs, annual operation and maintenance costs and annualized cost for a siloxane removal system
based on user input data (SCAQMD 2014).39
The SCAQMD may be one of the first air districts with such strict NOx and VOC emission
limits, but it will likely not be the last. To meet the EPA's 2015 standard for ozone, other
jurisdictions may similarly focus on reducing NOx and VOCs from stationary engines.
Compressed RNG: Scale & Demand
Scale affects project costs. The greater the flow rate, the smaller the per-unit cost ($/GGE). The
smallest-scale system analyzed (the BioCNG 50 system) is sized for an average biogas input
flow of 50 SCFM or 72,000 cubic feet per day. There are few existing digesters in California
equipped to generate biogas at the 50 scfm rate. More than half of the state's WRRFs with
anaerobic digesters, for example, treat less than 7 MGD; processing only wastewater, these
facilities would appear unlikely to produce enough biogas to justify the investment.40 And yet
public agencies (e.g., the Janesville WRRF and St. Landry Parish landfill) have been willing to
invest in smaller-scale projects, provided the project meets expected rates of return and adheres
to calculated payback horizons. Outside support (e.g., grants) and outside wastes (i.e., co-
digestion) would make any project, particularly smaller projects, more economical. Additional
research on co-digestion and project scale would provide valuable insight.
Another critical factor in the cost equation is the current status and planned expansion of natural
gas vehicles within an organization's fleet. A viable CNG project requires vehicles to use the
fuel. Some facilities such as the Joint Water Pollution Control Plant in Carson (CA), which
sells approximately 1,000 GGE/day to district vehicles, buses, and other commercial and public
users could dedicate biogas to producing compressed RNG, but will not until there is
adequate demand (Boehmke 2015). Similarly, the Janesville (WI) WRRF has the capacity to
dedicate more biogas to CNG, but, until it acquires additional dual-fuel vehicles, will prioritize
electricity and heat (Ely and Rock 2014). The present analysis did not consider the cost of
acquiring and/or converting and maintaining CNG vehicles. Nor did it consider the relationship
between economies of scale and fleet size (i.e., that larger volumes of CNG will require a larger
fleet, the acquisition and maintenance of which will require a larger investment). Here too,
additional research would assist future projects.
39 The Biogas Cleanup System Cost Estimator Toolkit is available here:
http://www.aamd.gov/home/regulations/rules/support-documents. It can be found_under the heading, Rule 1110.2.
40 According to data collected from EPA Region 9's annual biosolids reports, 76 of California's WRRFs with
anaerobic digesters have an Average Dry Weather Flow (ADWF) of less than 7.2 million gallons per day (MGD).
Assuming a wastewater flow of 1 MGD could produce 10,000 cubic feet of biogas (USEPA 2011), a facility treating
7.2 MGD could produce 72,000 cubic feet per day.
50
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Pipeline Injection: Scale, Clean-Up & Interconnection
Scale also influences pipeline injection project economics. Upgrading biogas to CNG vehicle
fuel can be competitive with diesel in many cases, making it an attractive transportation fuel;
whereas upgrading and injecting biogas into the pipeline is more expensive than conventional
gas, making injection a costly alternative (Gorrie 2014). Produced in smaller quantities than
natural gas and requiring more expensive processing, the production cost of biogas is inherently
higher than fossil fuel gas (Boehmke 2015). Additionally, natural gas prices are at a decade-low
(EIA 2015). For these reasons, scale is a significant consideration. Additional research on the
size and costs of existing U.S. and European biomethane pipeline projects would provide
valuable insight.
Perhaps even more significant for California biogas facilities are the costs associated with
meeting the CPUC biomethane quality standards and the interconnection fees charged by the
state's Investor Owned Utility (IOUs). California Assembly Bill 1900 (Chapter 602, Statutes of
2012) required the CPUC to develop standards for constituents in biogas to protect human health
and pipeline integrity. The resulting January 2014 rule requires testing, monitoring and
controlling for 17 constituents of concern, as well as a heating content requirement of 990 Btu.
Industry advocates have described the requirements as "cost-prohibitive" (Levin, Mitchell et al.
2014). Relatedly, the cost of interconnecting a biogas facility to the common carrier pipeline is
high, according to the State's IOUs, over a million dollars (CPUC 2015).
The Coalition for Renewable Natural Gas (CRNG) estimates the initial cost of a pipeline
biomethane project in California to be between $2 and $3.8 million, with annual costs exceeding
$400,000 (CRNG 2015). These California-specific costs for biomethane into the pipeline are
included in this report's cost estimates, presented earlier in Table 29 & Figure 27. As additional
projects come on-line in California, a close examination of project economics, including the role
of federal and state subsidies, would be useful. The present analysis did not consider how grants
and incentives would affect pipeline injection project costs.
Collecting & Processing High Strength Organic Wastes
For facilities handling high strength organic wastesranging from source-separated organics via
municipal collection programs to food processing facility discardsmanagers will need to invest
in infrastructure to collect and process the material. Methods employed to collect high strength
organic wastes will differ depending on the facility type, size and location. Inasmuch, collection
costs will vary.
Generally, processing high strength organic wastes involves chopping, grinding, and screening
the material to create a slurry which is fed into the digesters. In Food Waste to Energy. Ely and
Rock (2014) describe the processing protocols of six WRRFs and include various projects costs.
Costs for constructing food waste receiving stations ranged from $800,000 to $5,000,000.
Needless to say, processing costs also vary depending on unique facility characteristics.
While significant, the costs associated with collecting and processing high strength organic
wastes are not included in this analysis.
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Managing Digestate
In California, the land application of biosolids is heavily regulated, and, in some counties,
effectively banned. Inasmuch, the cost of managing biosolids varies, depending on the
management option, tipping fees, and travel distance. According to the 2014 Southern California
Alliance of Publicly-Owned Treatment Works (SCAP) survey, the average cost for managing
biosolids for Southern Californian Publicly Owned Treatment Works (POTWs) was $53.94/ton,
ranging from a low of $5.40/ton for landfill Alternative Daily Cover (ADC) to a high of $89.50
for deep well injection (SCAP 2015). Table 34 summarizes the results of the SCAP survey,
showing the range and average costs for several different biosolids management strategies.
Table 34. Range and average costs of different biosolids management strategies.
Biosolids Management Strategy
Range ($/ton)
Average ($/ton)
Composting
$29.41 to $84.00
$56.75
Landfill Alternative Daily Cover
$5.40 to $61.76
$31.72
Deep Well Injection
$89.50
$89.50
Land Application
$39.00 to $57.00
$47.13
Landfill, Direct Burial
$45.00 to $52.50
$50.41
Source: (SCAP 2015)
Depending on the digester type (i.e., wet or dry), the proximity of a composting facility (to cure
the solid digestate), and the end-use (land application, ADC, etc.), the cost of managing digestate
from a stand-alone digester will vary considerably. As many stand-alone digesters are relatively
new operations, much remains to be seen regarding overall project operation and maintenance
costs. Case studies examining the economics of stand-alone digester systems, including the costs
and revenues associated with co-products such as digestate can be found in the literature
(Ghafoori, Flynn et al. 2007, Gebrezgabher, Meuwissen et al. 2010, Golkowska, Vazquez-Rowe
et al. 2014, Monlau, Sambusiti et al. 2015) but are, for the most part, based in Europe. Similar
U.S. and California case studies are needed.
Unlike digestate from water resource recovery facilities and stand-alone digesters, dairy digestate
can be used on-site. Depending on its water content, digestate can be spray-applied to crops as a
fertilizer supplement or replacement, used as compost material or livestock bedding material
(ESA 2011). Digestate management typically does not cost a dairy much, it may even generate a
small revenue; see the additional sources discussion in the Primary Revenue section below.
Also omitted from this analysis are the environmental costs associated with managing digestate.
For example, the emissions analysis did not consider the fuel that would be consumed by trucks
hauling material to a land-application site; nor did it consider the potential N2O that would be
emitted if the digestate were improperly managed.
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Primary Revenue: Energy Savings, Sales & Subsidies
Biogas facilities can generate significant sources of revenue, which are dependent on the biogas
end use, as well as federal, state and local regulations, policies and incentives. Global cumulative
revenue from investment in biogas production capacity is expected to reach $25.8 billion
between 2015 and 2024, according to Navigant Research (Navigant 2015). Revenues include
cost savings from on-site energy operating costs, such as waste heat recovery and electricity use
on-site, as well as off-site sales, including exporting the electricity to the grid or producing RNG
to fuel vehicles or inject in the natural gas utility pipeline. Additionally, biogas-to-energy
projects are eligible for local, state and federal subsidies, which can play an important role in
project financing. However, current low natural gas prices make biogas projects difficult to
finance. This analysis did not take into consideration energy savings, sales, and subsidies when
evaluating project economics. These factors could substantially lessen costs.
Offsetting Heat & Power Costs
Biogas combusted in engines including reciprocating engines, microturbines, turbines and
fuel cells produces both electricity and heat. Producing heat and electricity on-site has a
number of benefits, including generating power at a cost below retail electricity rates and
displacing purchased fuels for thermal needs. For those biogas facilities with considerable power
expenses, on-site generation is particularly attractive. For WRRFs, energy bills can be -30% of
total O&M costs (Cams 2005), usually representing a facility's second or third biggest expense.
The electric power produced by combusting biogas in an engine can offset all or most of a
WRRF's power demand, and the thermal energy produced by the CHP system can be used to
meet digester heat loads and, in some cases, for space heating (USEPA 2011).
Selling Excess Energy
Biogas can also be exported and sold off-site, either as pipeline quality biomethane, a vehicle
fuel, or electricity. To sell electricity to a utility or nearby facility, a biogas facility can
interconnect. Once interconnected, a facility can sell to a third party by developing a Power
Purchase Agreement (PPA) or to the local electric utility by establishing a net metering
agreement. Net metering credits renewable energy generators that deliver to the grid. The local
utility tracks each kWh consumed and received. When a biogas facility generates more
electricity than it consumes, the electric utility credits the excess delivered to the grid. These
credits can, in turn, be used to offset the cost of power purchased from the utility when the
biogas facility consumes more than it generates.
In California, the major electric utilities must offer net metering to all eligible facilities (1 MW
or less solar, wind, fuel cell or biogas systems) until the facilities reach a legislated limit (DSIRE
2015). Larger capacity systems are eligible for other renewable energy procurement programs.
Systems under 3 MW may participate in California's Feed-in Tariff (FIT) program (CPUC
2014a); systems greater than 3 MW and less than 20 MW may participate in the Renewable
Auction Mechanism (RAM) program (CPUC 2014b). Unlike net-metering, the FIT and RAM
programs do not commit utilities to purchasing the electricity at full retail value; rather, as with
PPAs, the utilities commit to buying electricity at a predetermined rate over a predetermined
time period.
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Renewable Energy Certificates (RECs)
A biogas system producer may also sell the on-site generated electricity in the form of a REC. In
California, as with other states, RECs are used to show compliance with the Renewable Portfolio
Standard (RPS) and can be traded in voluntary markets (Green and Koostra 2015). A state's RPS
requires IOUs, electric service provides and community choice aggregators to increase
procurement from eligible renewable energy resources. California's current RPS goal is to
procure 50% renewables by 2030 (De Leon 2015).
A REC is a certificate that represents the generation of one MWh of electricity from an eligible
source of renewable energy and represents the property rights, in this case, to the non-power
qualities of electricity generated from biogas. Because the RECs are not tied to the physical
delivery of electrons, organizations are able to purchase green power from suppliers other than
their local electricity provider. While RECs offer increased contracting convenience, they do not
provide the same protection against price volatility as long-term contracts (USDOE 2010).
EPA's Renewable Fuel Standard & Renewable Identification Number (REN)
Credits
Managed by the U.S. EPA, the RFS program mandates that 36 billion gallons of renewable fuel
be blended into the nation's transportation fuel by 2022 (USEPA 2016b). The RFS obligates
producers of gasoline or diesel (including refiners, importers, and blenders) to meet the mandate,
and established a trading program to ensure compliance. The trading program allows obligated
parties to comply through a credit based program, with the credits being Renewable
Identification Numbers (RINs).
A RIN is a 38-digit number generated by the production or import of qualifying renewable fuel;
it uniquely identifies the fuel type, providing, among other details, information about the
category of fuel it qualifies for under the program. RFS fuel categories include cellulosic biofuel,
biomass-based diesel, advanced biofuels, and renewable fuel, commonly referred to as
conventional biofuels. The obligated parties satisfy the RFS obligations for each category under
the program by obtaining the necessary number and type of RINs. RINs are generated by the
renewable fuel-producer and, once blended, the RINs are separated and can be banked, sold or
traded amongst registered parties. These Renewable Volume Obligations (RVOs) change each
year. Table 35 shows the 2016 RVOs associated with each fuel category (USEPA 2016b).
Table 35. 2016 Renewable Volume Obligations.
Fuel category
2016 RVO Volumes
(billion gallons)
2016 RVO Percentages
(of total U.S. fuel produced)
Cellulosic biofuels
0.23
0.128%
Biomass-based diesel
1.9
1.59%
Advanced biofuels
3.61
2.01%
Renewable fuel
18.11
10.10%
Biogas-derived fuels had been classified as advanced biofuels, but were reclassified to be
cellulosic biofuels in the July 2014 Pathways II Final Rule (USEPA 2014). Biogas-derived fuels
and electricity used in the transportation sector (to, for example, power an electric car) can now
54
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generate cellulosic RINs. RINs are traded in an open marketplace, and prices are controlled by
supply and demand. The market will likely grow as RVOs increase.
CARB's LCFS Credits
California's adoption of the Global Warming Solutions Act of 2006 set in motion a series of
policies to reduce GHG emissions in the state. The LCFS and Cap-and-Trade regulations
established a market for proper capture and reuse of methane generated from AD projects, which
can significantly reduce GHG emissions. The LCFS requires at least a 10% reduction of carbon
intensity of California's transportation fuels by 2020. The carbon intensity of RNG is
significantly lower than many other fuel pathways, which can be blended to maintain a price
advantage over diesel while providing a net carbon saving. Thus, LCFS credits can generate
substantial financial benefits. From August 2015 LCFS credit prices, the potential value of LCFS
credits from dairies could be about $400 million per year.41' 42
California's Carbon Offset Credits & Greenhouse Gas Reduction Fund
California's GHG Reduction Fund was established to receive proceeds generated from the Cap-
and-Trade auctions.43 This Cap-and-Trade regulation allows for generation of offset credits by
eligible biogas digester projects, in addition to the LCFS and RIN credits. The State of California
determines carbon offset protocols for quantifying carbon reductions and manages the sale of
offset credits.44 Even flared biogas can generate verified carbon offsets. Environmental credits
may provide financial returns yet their price greatly fluctuates. California's price in carbon has
fluctuated from the peak of $23.00/ton CCheq in September 2011 near the launch of this program
to $11.60/ton CCheq.45
Additional Revenues: Tipping Fees & Co-Products
In addition to the money saved by reducing on-site energy costs and the money earned by
exporting energy, biogas facilities can generate additional revenue by diversifying their source
portfolio. A WRRF or a dairy co-digesting with high-strength organic waste [i.e., organic waste
with a high energy value, such as Fats, Oils and Grease (FOG)] can increase revenue by boosting
biogas production and by charging tipping fees. While upgrading a facility to receive high
strength organic wastes can require capital improvements, the benefits typically outweigh the
costs.
Depending on the amount and type of material co-digested, biogas yields can improve
significantly. Three facilities profiled in a recent EPA paper reported biogas increases of at least
41 Assumes California dairies produce 34% of national biogas potential from U.S. dairies, with a carbon intensity of
-100 and an average August 2015 credit trading price of $57.
http://www.arb.ca.gov/fuels/lcfs/lrtmonthlvcreditreports.htm.
42 Informa Economics (2013) National Market Value of Anaerobic Digester Products, Prepared for the Innovation
Center for U.S. Dairy, February.
http://www.usdairv.eom/~/media/usd/public/nationalmarketvalueofanaerobicdigesterproducts.pdf.
43 AB 1532 (Perez, Chapter 807), SB 535 (De Leon, Chapter 830), and SB 1018 (Senate Budget Committee, Chapter
39) established the GHG Reduction Fund to receive Cap-and-Trade auction proceeds.
44 For a list of protocols and offset projects, see: http://www.arb.ca.gov/cc/capandtrade/offsets/offsets.htm.
45 See https://www.theice.com/marketdata/reports/142. and http://calcarbondash.org/.
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100%; one, the Sheboygan (WI) WRRF, observed a 300% increase (Ely and Rock 2014). A 700-
cow dairy in northwest Washington co-digesting with 16% outside organic wastes more than
doubled biogas production. Tipping fees too can bring in substantial revenues. Of the facilities
profiled in the aforementioned EPA paper, the EBMUD facility in Oakland, CA earned $8
million in tipping fees in one year (Ely and Rock 2014). The co-digesting dairy in northwest
Washington almost quadrupled annual digester revenues (Bishop and Shumway 2009, Frear,
Liao et al. 2011).
Some biogas facilities could also generate revenue by recovering nutrients and selling enhanced
fertilizer products. WRRFs such as the Hampton Roads Sanitation District recover and convert
phosphorus and ammonia into a slow-release fertilizer, the revenues from which offset capital
and operating costs (NACWA-WERF-WEF 2013). Concentrated Animal Feedlot Operations
(CAFOs) are also recovering nutrients to create agricultural products. The Double A and Big Sky
dairies in Jerome (ID), the Bio-Town facility in Reynolds (IN), and the Qualco Digester in
Monroe (WA) are a few examples of dairy digester systems equipped to economically harvest
phosphorus. The nutrient removal strategies of these and other CAFOs are reviewed in a recent
study prepared for the Innovation Center for U.S. Dairy (Ma & Kennedy et al. 2013). Biogas
facilities operating in regions with nutrient trading programs46 may one day find nutrient
recovery particularly lucrative.47
Whether or not processed to optimize nutrient recovery, the digestate from WRRFs and stand-
alone digesters can be used as soil amendments, more often at a cost to the facility (see the
Additional Costs section above). Dairies, on the other hand, can generate modest revenue by
managing liquid and solid digestate on- and off-site. The effluent can be used on-site, reducing
or eliminating the need for synthetic fertilizers. It can also be sold to adjacent farms. The solid
digestate can also be used as a fertilizer on-site, dried and used as animal bedding, or sold
commercially. The potential offset costs and earned profits are considered minor (ESA 2011).
While the economic benefits of land-applying digestate may be evolving, the environmental
benefits are well established. Applying biosolids, manure, and/or cured digestate (i.e. compost)
helps build healthy soils by providing nutrients, which reduce the need for synthetic fertilizers
and pesticides; and by increasing organic matter, which has many benefits, including reducing
erosion, sequestering carbon, supporting soil biodiversity, and, of course, retaining water.
Increased Soil Organic Matter (SOM) helps to aggregate mineral particles, building a network of
pore spaces that enables water to reach plant roots faster and to stay in the soil longer. Increased
soil water results in greater drought tolerance for non-irrigated crops and less frequent irrigation
for irrigated crops. Soil amendments also reduce evaporation of water from soils, further
reducing irrigation demands (Brown 2014). As the California drought enters its fifth year,
support for SOM is gaining even more ground through the Healthy Soils Initiative (CDFA 2016).
46 e.g., the Laguna de Santa Rosa water quality credit trading programs, the Klamath Tracking and Accounting
program, and the Lake Tahoe Clarity Crediting Program.
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Markets for AD co-products, notably compost and soil amendments, need to be built out and
strengthened. This would provide an important source of revenue, helping to finance biogas
projects in the face of low natural gas prices and relatively few incentives. The future will likely
see more enhanced fertilizer products including separated and concentrated nutrients (i.e.,
nitrogen, phosphorous, potassium, etc.) sold in liquid, pellet or dry form. The residual fibrous
material may be incorporated into more valuable products that improve soil moisture retention
and nutrient release; other prospects for fibers include plant boxes, land stabilization materials,
pressboard for home construction, and additives to increase the strength of plastics (Gorrie
2014a). Whether or not the California drought persists, recycled effluent may also play a role in
project financing.
Policy Pipeline
Government regulations and policies can drastically affect viability of biogas projects.
Regulatory actions can expedite, but also hinder or all together halt, the development of projects.
Various policies which can include regulations, mandates, standards, incentives and tax
credits may have strong influence on success of a given biogas project. Due to the still
nascent nature of these technologies and the biogas market as a whole, federal, state and local
policies are constantly changing. The considerable uncertainty about these government actions
causes significant market volatility, often leading to difficulties in securing project financing. For
example, because of the volatility of RIN and LCFS credits, investors are often reluctant to
provide the necessary financing for biogas digester projects. Strong longer term policies at
various levels of government can help ensure the success and longevity of biogas projects.
Federal Policies
2015 NAAQS for Ground-Level Ozone
Ground level ozone is not emitted directly into the air, but is created by chemical reactions
between NOx, methane and VOCs in the presence of sunlight. Emissions from industrial
facilities and electric utilities, motor vehicle exhaust, gasoline vapors, and chemical solvents are
some of the major sources of NOx and VOCs. Breathing ozone can trigger a variety of health
problems, particularly for children, the elderly, and people of all ages who have lung diseases
such as asthma (USEPA 2015).
In October 2015, EPA strengthened the NAAQS for ground-level ozone to 70 ppb. The benefits
of meeting the standards in California are estimated at $1.2 to $2.1 billion annually after 2025.
This includes the value of avoiding harmful health effects, such as premature deaths, missed
work days and asthma-related emergency room visits. While beneficial, achieving the reductions
in California will be difficult. The state has unique air quality challenges due to the combination
of meteorology and topography, population growth and the pollution burden associated with
mobile sources (USEPA 2015a).
The majority of California's NOxemissions are generated by mobile sources. According to 2012
estimates, mobile sources (mainly, on-road motor vehicles) are responsible for nearly 83% of the
2,106 tons of NOx emitted daily (CARB 2015). To reduce these emissions, California has spent
billions of dollars on innovative technologies such as zero-emission trucks and buses, hybrid
heavy-duty vehicles, and zero-emission freight equipment. In addition, CARB has adopted an
57
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optional low N0Xemission standard for on-road heavy-duty engines, encouraging engine
manufactures to introduce new technologies to reduce emissions below the current mandatory
emission standards for model years 2010 and later (CARB 2014).
Certification to lower optional standards could enable certified low- engines to become eligible
for CARB incentive funding (CARB 2015c). As of February 2016, natural gas-fueled engines
have been certified by both the EPA and CARB to meet CARB's 0.02 grams per break-
horsepower hour optional low NOxemission standard, showing 90% lower NOxemissions than
EPA's current 2010 standard (CARB 2016). Local air districts have also invested in mobile
source reductions. The SCAQMD, for example, has funded projects to improve engine design,
battery life, fuel cells and powertrains for electric vehicles.
Despite on-going state and local efforts to reduce mobile sources, nearly half of all California
counties, representing roughly 80% of the state's population, exceed the NAAQS for ground-
level ozone. In Figure 40, the map at left, shows the California counties in nonattainment for the
2008 ozone standard of 75 ppb. The map on the right shows the counties expected to be in
nonattainment for the 2015 ozone standard of 70 ppb. Air districts struggling to meet the ozone
NAAQS are requiring further NOx reductions from stationary sources (e.g., Rule 1110.2) even
though, as with the SCAQMD, they represent less than 10% of total emissions (CARB 2015). As
explained in South Coast's Air Quality Management Plan, "the challenges are too great, the
stakes too high, and the deadlines too soon" (SCAQMD 2013).
CALIFORNIA BIQGA3 PRODUCERS AND COUNTIES COMPARED AGAINST
THE D.C75 PPM 2038 E-HOUR OZONE STANDARD
tt-ojjiB lisatrr*
m Swid-Mcm
-
* WW* Wrin traurtnari ^KSrty »«- DgMtv
Landil Cetodfrrs Ufepn
I I Sroit
CZ3 Muaviti
1 I
I I Osirrtf bstnsary
CALIFORNIA 9IOGLAS PRODUCERS AND COUNTIES COMPARED AGAINST
THE 0.C7D PPM 2Qt5 8-HOUR OZONE STANDARD
3:;i» I"' - dut »t«
¦ 31an£-M=n« Dip**-
* Land* J Biijb
/Mat TtnlbitM K'KlHy *rt-
B_J uua
I < H o :«r ai
^ . I I Co-TTtf L
* ¦ JIvi
\
- '!«* tji - i
Figure 40. Biogas facilities and attainment designations for 2008 and 2015 ozone standard.
58
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The biogas industry will be an important partner in reaching ozone reduction goals. Those
counties exceeding the ozone standard are also the counties where the majority of the state's
biogas producers reside. Nearly 60% of the landfills with gas capture systems, wastewater
treatment facilities with anaerobic digesters, dairies with digesters and stand-alone digesters
operated in counties exceeding 2008 ozone standard of 75 ppb. Nearly 70% of biogas producers
operate in counties exceeding the 2015 standard of 70 ppb.
Clean Power Plan
EPA's Clean Power Plan establishes the first-ever national standards to limit carbon pollution
from existing power plants and to a national reduce CO2 emissions by 32% from 2005 levels by
2030. Under this rule, states can tailor implementation plans to meet their respective energy,
environmental and economic needs and goals. EPA anticipates that renewable energy will be a
significant strategy for states and existing sources (USEPA 2015b). On February 9, 2016, the
U.S. Supreme Court stayed the Clean Power Plan pending judicial review. The effect of the stay
is that there is no obligation to comply with the Clean Power Plan, and states therefore have no
obligation to develop state plans responsive to the Clean Power Plan. The Court's decision was
not on the merits of the rule. EPA firmly believes the Clean Power Plan will be upheld when the
merits are considered because the rule rests on strong scientific and legal foundations. For the
states that choose to continue to work to cut carbon pollution from power plants and seek the
agency's guidance and assistance, EPA will continue to provide tools and support.
RFS Renewable Volume Obligations & RIN Classification
EPA's RFS has made significant changes in classifying RNG or biogas used as a transportation
fuel from specified sources, as well as setting annual Renewable Volume Obligations (RVOs) or
total amount of required renewable fuels. RNG generated from biogas sources was once
classified as an advanced biofuel RIN renewable fuel category, yet EPA's July 2014 Pathways II
Final Rule now lists RNG as a cellulosic biofuel. Since RIN credits are traded in an open
marketplace, prices are controlled by supply and demand. Cellulosic RIN credits may become
more valuable because: 1) they have been relatively rare, and obligated parties must meet RVOs;
and 2) they are the "one-stop-shop" of the RIN credit marketplace, as they can be used to meet
the RVOs of any RFS fuel category. In addition to this major policy change, which has led to
increasing the value of RNG RIN credits, EPA's November 2015 final RFS rule set annual
RVOs or total amounts of renewable fuel required for 2016 and a proposed 2017 RVO for
biomass-based diesel. The final 2016 volumes shows a significant growth in renewable fuels,
especially for cellulosic biofuel, which includes RNG, increasing seven times from 2014 market
production levels.
State of California Policies
Cap-and-Trade Investment Plan for Auction Proceeds
The California State government determines the process for allocating auction proceeds
generated from the Cap-and-Trade Program. The Investment Plan identifies near- and long-term
GHG emission reduction goals and targets and recommended investments. These GHG reduction
goals and funding levels provide signals on the state's priority and opportunities to reduce
GHGs. Support for various biogas projects, used both for electricity generation and as RNG fuel,
are included in the December 2015 Cap-and-Trade Auction Proceeds Revised Draft Second
59
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Investment Plan (CARB 2015b). As the Governor and legislature are finalizing this Plan in 2016,
biogas projects are likely to be eligible to receive significant levels of funding support during
2016-17.
LCFS Re-Certification
Similar to EPA's RFS, California's LCFS is regularly updated, which affects RNG. CARB
periodically updates the LCFS (as with any of its programs) in order to make sure the regulatory
program remains current with the latest science and technology. This can result in adjustments to
the life-cycle analysis of some of the fuel pathways used to assign carbon intensity scores under
the LCFS program. Any such adjustments may require a re-certification of the fuel pathway. The
re-certification updates the carbon intensity values certified under the previous LCFS regulation.
This re-certification may change how a fuel is classified or adjust its carbon intensity (CI)
(CARB 2015e).
Bioenergy Feed-In-Tariff
California's Bioenergy FIT (per SB 1122 (Rubio 2012)) requires the CPUC to direct IOUs to
procure 250 MW (cumulative, statewide) of new small biopower (less than 3 MW per project) in
a separate IOU feed-in tariff program (Bioenergy Feed-in-Tariff). The 250 cumulative MW is
allocated by resource type: 110 MW urban biogas, 90 MW agricultural bioenergy (including
dairies), and 50 MW from material from sustainable forest management.
Renewable Portfolio & Golden State Standards
California's RPS and SB 350 (De Leon and Leno 2015), the Golden State Standards, set
renewable energy consumption requirements. SB 350 increased the RPS, originally to 33% by
2020 to now 50% by 2030 (De Leon 2015). This new state standard will help increase the
amount of electricity generated from biogas.
Governor Brown's Clean Energy Jobs Plan
Governor Brown's Clean Energy Jobs Plan calls for 20 gigawatts (GWs) of new renewable
generation by 2020. The Plan calls for 8 GW from large scale facilities of 20 MW or higher and
for 12 GW from distributed generation from facilities of less than 20 MW per project (Brown
2011).
Short-Lived Climate Pollutants
To meet the Governor's climate goals, significantly reducing Short-Lived Climate Pollutants
(SLCP), such as methane, will be necessary. CARB is developing a comprehensive strategy to
reduce these emissions (CARB 2015d). Capturing methane via biogas digesters is included in the
state's draft strategy, which may include regulations, such as manure management practices
(including digesters), on new dairies.
Natural Resources & Waste Diversion Targets & Goals
CalRecycle implements waste division strategies to cut GHG emissions, primarily methane, by
reducing the amount of municipal solid waste disposed in landfills. California's 75% diversion
and compositing goal by 2020 will greatly increase digester projects, anticipating the reduction
of methane emissions by 40% from 2005 levels by 2030 (CalRecycle 2011). Utilizing organic
waste through digesters will help California meet the State's RPS and bioenergy targets.
60
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However, a significant investment in infrastructure to support resource recovery from organic
waste will be needed.
Strong, long-term policies are greatly needed to help stabilize the market for biogas projects.
These government actions serve as market drivers that can lead to greater certainty and reliability
in the revenues generated from biogas end products, such as electricity or natural gas. Project
investors often need long-term market certainty to finance high capital cost projects, such as
digester projects. As states set higher standards for more renewable energy and fuel production,
biogas projects will only increase.
Governor Brown's Goal of Fifty Percent Reduction in Petroleum Use
Additional funding under the Governor's Budget if made available to CARB under the Low
Carbon Transportation Program and to the CEC under its Alternative and Renewable Fuel and
Vehicle Technology Program (ARFVTP) will also help incentivize the development of the
state's indigenous biogas production resources. CARB is proposing to establish a $40 million
Low Carbon Fuel Incentive Program as part of its 2016-17 Funding Plan for the Air Quality
Improvement Program and Low Carbon Transportation Greenhouse Gas Reduction Fund
Investments (CARB 2016b). The Governor is also proposing to add an additional $25 million to
the Alternative and Renewable Fuel and Vehicle Technology Program ".. .to provide incentives
for in-state biofuel production through the expansion of existing facilities or the construction of
new facilities" [Brown 2016 (pg. 97)].
Renewable Hydrogen and Fuel Cell Electric Vehicles
SB 1505 (Lowenthal Chapter 877 Statutes of 2006) requires that at least 33% of hydrogen
produced in California, in the aggregate, be produced from renewables. Auto-manufacturers have
begun delivering the first production fuel cell electric vehicles (FCEV) to California and the
industry expects to be delivering thousands of FCEVs within the next few years (CAFCP 2015).
The resulting increased demand for renewable hydrogen to fuel these vehicles should help
incentivize the market for the development of RNG production which can serve as a feedstock
for the production of renewable hydrogen (Pyper 2014). California's ambitions to develop
Advanced Clean Transit including the use of fuel cell electric buses will also add to the increased
demand for RNG as a feedstock for renewable-hydrogen fuel (CAFCP 2013).
61
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4. Conclusions
Economic performance
Not taking into consideration energy savings, sales or subsidies, flaring is the lowest cost biogas
management option at less than $l/MMBtu (input flow basis). In order of increasing cost are gas
turbines, with costs ranging from $3.25 to $4.20/MMBtu; reciprocating engines, with costs
ranging from $4.42 to $5.34/MMBtu; microturbines, with costs ranging from $4.29 to
$6.85/MMBtu; upgrading and converting to CNG, with costs ranging from $3.4 to
$12.8/MMBtu; fuel cells, with costs ranging from $10.41 to $18.41/MMBtu; and, upgrading the
biogas for pipeline injection, with costs ranging from $7 to $25/MMBtu. (See Figure 34.) There
are economies of scale for all of the processes investigated with fuel cells, microturbines and
pipeline injection showing strong economies of scale.
For situations where biogas is already available (e.g., landfills or WRRFs), management of
biogas using microturbines, reciprocating engines, and gas turbines would compete with
industrial and commercial electricity prices in California, which ranged from $0.12-$0.16 per
kwh in 2015 (EIA 2016). Those technologies also fall below the California "bioFIT" floor
($0.125/kWh), suggesting they would be economic at the bioFIT price (Figure 35). Regarding
the CNG pathway, the fuel production cost (for situations where biogas is already available)
ranges from $0.50/GGE for the 1600 SCFM system to $2.40/GGE for the 50 SCFM system;
these are lower than current California fuel prices and the $2.51/gallon average of the last 20
years (CEC 2016).
As acknowledged throughout this report, our cost analysis is narrow in its scope. It only includes
costs for the biogas conversion or upgrading technology. Costs for producing the raw biogas
(i.e., digesters, feedstock handling, etc.) are not included. Conversely, the analysis does not
consider those factors that would offset projects costs, including primary (i.e., energy sales,
savings, and subsidies) and secondary (i.e., tipping fees and the sale of co-products) sources of
revenue. Our analysis is one piece of a much bigger economic puzzle.
Environmental performance
The analysis compared the criteria pollutant (NOx, CO, PM, VOC and SOx) and greenhouse gas
(CH4, N2O and CO2) emissions associated with on-site use or upgrading. For criteria pollutants,
in order of decreasing emissions, flares have the highest NOx emissions (as lb/MMBtu gas
input), followed by reciprocating engines (even those meeting 1110.2 limits), low NOx gas
turbines, CNG systems with only 70% recovery, microturbines, gas turbines with SCR, CNG
systems with 85% recovery, pipeline injection, and fuel cells. The emissions factors for the other
criteria pollutants analyzed do not all follow that same sequence (Figure 38).
Combusting biogas emits criteria pollutants that exacerbate California's air quality challenges.
While the majority of California's NOx emissions are generated by mobile sources, reducing
criteria pollutant emissions from biogas sources is an important element in plans to improve air
quality regionally, and statewide. Simultaneously, generating energy from biogas is key to
62
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attaining greenhouse gas reduction goals. Previous studies have demonstrated the relatively low
carbon intensity of biogas-derived fuels, including several of the CARB LCFS pathways.
For greenhouse gas emissions, all devices emit small, but significant, amounts of methane as
"slip" (or unburned methane) from conversion devices or through leaks in processing equipment,
ranging from <1% to 2% of the incoming biogas. For biogas engines, microturbines and gas
turbines, average methane emissions are about two orders of magnitude larger than the California
eGRID factor (Figure 37). This is primarily due to relatively large methane slip compared to that
of the overall California grid. The N2O emissions for microturbines, gas turbines, and fuel cells
were about half that of the California grid. Reciprocating engine N2O emissions are about four
times the California grid average (Figure 38).
To compare to eGRID, biogenic CO2 emissions are not included in the CCheq emissions factor
calculations. Therefore, the CCheq equivalent emission factors for biogas fueled microturbines,
gas turbines, reciprocating engines, and fuel cells are all considerably lower than the California
eGRID factor (Figure 41, which is same as Figure 39).
CO
-Q
800
600
400
200
2 eq.
Reciprocating Microturbines Gas Turbines Fuel Cells
Engines
\ss\
CA eGRID
Figure 41. CCheq emissions for the bio-power technologies & CA eGRID.
As acknowledged throughout this report, the scope is limited and does not allow for a full system
or life-cycle emissions accounting. The boundary of the analyzed technologies starts with
already-produced biogas and examines only the emissions associated with on-site use or
upgrading. Upstream emissions, such as hauling material to a digester, and downstream
emissions, such as those from a biogas-fueled CNG vehicle, were not considered. Conversely,
the analysis did not incorporate downstream sinks, such as the carbon temporarily sequestered by
land-applying digestate. As with the economic analysis, our environmental analysis is one piece
of a much bigger emissions puzzle.
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Implications for Future Research and Policy
The narrow scope of our analysis helped to highlight the need for additional inquiries.
Circumstances unique to particular facilities affect project costs in big and small ways. For
example, how do differences in biogas quality affect cost? A source-specific analysis of project
costs - one that addresses the economics of removing problematic trace contaminants - would
provide greater and helpful insight.
Technology innovations and improvements that reduce costs or emissions are needed. With
respect to fuel cells operating on biogas, increased durability of stack components would reduce
operating costs while a larger number of installed and operating units would reduce installation
costs (due to learning and lower equipment production cost).
Geography too influences costs. Consider, for example, the facility- and location-specific
economics of flaring. Typically, landfills combusting biogas do not use waste heat; WRRFs do,
requiring both heat and power. But how might these facilities manage biogas in a region where
mountains and mobile sources interact to create the worst air quality in the nation? With stronger
emission limits on stationary engines, would it be more economical for landfills to flare rather
than upgrade? With greater on-site energy needs, what would flaring cost a WRRF? A more
nuanced analysis taking into consideration unique geographic conditions would assess project
costs with greater certainty.
A more encompassing and tailored accounting of what factors increase project costs is needed.
So too is a clearer assessment of what factors offset projects costs. In this report, we have
qualitatively described the federal and state grants and incentives available to support biogas
projects. But, more information regarding the impact of these incentives is needed. Moreover,
there is a need for quantitative information on the costs and benefits of secondary sources of
revenue. A complete cost analysis should consider those factors that increase biogas production
(e.g., co-digestion) and may otherwise boost the bottom-line (e.g., fertilizer sales).
For each opportunity there is to increase or offset costs, there seems an equal opportunity to fill
knowledge gaps. Take, for example, co-digestion at a WRRF. There is a growing consensus that
co-digestion improves project economics and can be the tipping point for investing in combined
heat and power (WERF 2012). Yet, if an on-site energy analysis were to consider the costs and
revenues associated with a prospective co-digestion effort, the analyst would lack essential data.
Information regarding feedstock availability, for example, is scantly available. Quantifying
organic waste volumes at scale is critical for an individual facility. Enabling the sector to do so
may be critical for the state.
The California Association of Sanitation Agencies (CASA) estimates existing WRRFs possess
the capacity to manage 75% of the food waste generated in California (CASA 2016). Given the
state mandate to reduce the disposal of organic waste by 50% by 2020, CASA's estimate raises
important policy questions. If WRRFs can manage such a large volume of California's food
waste while also bringing the state closer to reaching renewable energy goals, should co-
digestion projects be prioritized? Even if boosting biogas production emits criteria pollutants that
exacerbate California's air quality challenges?
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Evaluating impacts is no easy task. One approach can at once hinder and advance societal goals.
Diverting organics from landfills and into digesters limits rogue methane emissions, reducing
short-lived climate pollutants. Yet, combusting biogas in stationary engines can exacerbate local
air quality problems. Digestate-based fertilizer products build healthier soils, sequestering carbon
and increasing agricultural water efficiency. Yet, in some California counties, the land
application of biosolids is effectively banned. The less money a WRRF spends on energy, the
more it can invest in upgrades such as tertiary treatment, helping to expand local water supply
during drought. Yet, emission limits on stationary engines increase operating costs, restraining
WRRF budgets.
Some of these conflicts may be real, others perceived. Balancing state goals with local
ordinances and industry preferences to advance the projects and policies with the greatest net-
environmental benefit is a tall order. Future biogas research efforts could help lead the way by
considering broader upstream and downstream impacts as they pertain to cross-media goals.
How and at what cost can biogas projects realize clean energy, clean air, clean water, healthy soil
and waste diversion goals?
A first task could be to identify how to economically reduce criteria emissions from stationary
engines over a time period agreeable both to regulated facilities and local air districts. If after-gas
treatment technologies (e.g., SCR) on reciprocating engines are an acceptable interim solution,
how do we get there and what comes afterward? Our analysis and the SCAQMD assessment of
after-gas cleanup technologies are first steps. What additional research, legislative action or
funding solution will be next?
Our analysis has provided a side-by-side comparison, showing the environmental and economic
performance of seven different biogas applications in California. While not exhaustive, it
provides a bare bones synopsis. By doing so, we now have a generic baseline, a metric that can
be used measure progress. Shrinking costs and emissions reductions can be used to indicate the
efficacy of related technological and policy innovations. How these metrics change over the next
20 years will be telling.
Relevance to other states or regions
While the biogas utilization technologies discussed in this report are in use throughout the U.S.,
the detailed emissions performance and costs are specific to California. However, these results
may soon have utility for a larger area in the rest of the U.S. There are approximately 170
counties (home to 86 million people) in the rest of the U.S. that are designated marginal or
moderate non-attainment for 8-hour ozone (USEPA 2012b). The number (and severity) of ozone
non-attainment areas in the U.S. is expected to increase after implementing the more stringent
2015 ozone standard (USEPA 2015c).48
48 Final nonattainment area designations and classifications for the 2015 NAAQS ozone standard are expected in
October 2017. https://www.epa.gov/ozone-pollution/2015-ozone-naaqs-timelines
65
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Appendices
66
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Appendix A- Technology Summary Results Data
Microturbines
Capacity
Efficiency, HHV basis
Levelized
Cost
($/MWh)
Emissions (Ib/MWh)
kW
Gas Flow
input (SCFM)
Gas Flow
input
(MMBtu/h)
(%)
Heat Rate
(Btu/kWh)
NOx
CO
PM
voc
SOx
30
13.1
0.47
22
15,700
126
0.251
0.266
0.010
0.123
1.044
65
26.4
0.95
23
14,600
94
0.234
0.248
0.010
0.115
0.975
200
73.5
2.6
26
13,200
76
0.212
0.224
0.009
0.104
0.882
250
90.0
3.2
26
13,000
68
0.208
0.220
0.009
0.102
0.864
333
116.9
4.2
27
12,600
64
0.202
0.214
0.008
0.099
0.842
Emission Factor (Ib/MMBtu)
NOx
CO
PM
VOC
SOx
0.0160
0.0170
0.00067
0.0079
0.0667
kW
Greenhouse Gases (Ib/MWh)
Greenhouse Gases
(lb C02eq/MWh)
ch4
C02*
N20
ch4
C02*
N20
30
2.6
3,000
0.004
88.8
3,000
1.19
65
2.4
2,800
0.004
82.9
2,800
1.11
200
2.2
2,530
0.003
75.0
2,530
1.01
250
2.2
2,480
0.003
73.5
2,480
0.99
333
2.1
2,420
0.003
71.7
2,420
0.96
Emission Factor (Ib/MMBtu)
GWP100
ch4
C02*
N20
ch4
C02*
N20
0.167
191.3
0.00026
34
1
298
* Biogenic CO2 emissions
67
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Gas Turbines
Capacity
Efficiency, HHV
basis
Levelized
Cost
Emissions (Ib/MWh)
low-NOx Combustor
SCR or ultra low NOx
AP-42
(no control)
kW
Gas
Flow
input
(SCFM)
Gas Flow
input
(MMBtu/h)
(%)
Heat Rate
(Btu/kWh)
($/MWh)
NOx
CO
voc
SOx
NOx
CO
VOC
SOx
PM
1200
542
19.5
21
16,300
80.4
0.50
0.059
0.12
1.018
0.18
0.21
0.011
0.075
0.20
3500
1309
47.1
25
13,500
55.0
0.42
0.05
0.10
0.842
0.15
0.17
0.009
0.062
0.16
4600
1634
58.8
27
12,800
50.1
0.40
0.05
0.09
0.800
0.14
0.16
0.009
0.059
0.15
5700
1886
67.9
29
11,900
46.6
0.37
0.04
0.09
0.745
0.13
0.15
0.008
0.055
0.14
6300
1997
71.9
30
11,400
45.0
0.35
0.04
0.08
0.714
0.13
0.14
0.008
0.053
0.14
7900
2402
86.5
31
10,900
41.8
0.34
0.04
0.08
0.685
0.12
0.14
0.008
0.051
0.13
Emission
Factor (1
b/MMBtu)
NOx
CO
VOC
SOx
NOx
CO
VOC
SOx
PM
0.0309
0.0037
0.0072
0.0626
0.0112
0.0127
0.0007
0.0046
0.01200
kW
Greenhouse Gases (Ib/MWh)
Greenhouse Ga
(lb COzeq/MW
ses
h)
ch4
C02*
l\l20
ch4
C02*
N20
1200
2.7
3,113
0.0060
92.3
3,113
1.79
3500
2.2
2,576
0.0034
76.3
2,576
1.03
4600
2.1
2,447
0.0033
72.5
2,447
0.98
5700
2.0
2,279
0.0030
67.5
2,279
0.91
6300
1.9
2,183
0.0029
64.7
2,183
0.87
7900
1.8
2,095
0.0028
62.1
2,095
0.83
GHG Emission Factors
(Ib/MMBtu)
GWP100
ch4
C02*
l\l20
ch4
C02*
N20
0.1668
191.3
0.00026
34
1
298
*Biogenic CO2 emissions
-------
Reciprocating Engines
Capacity
Efficiency, HHV
basis
Level ized
Cost
Emissions (Ib/MWh)
Greenhouse Gases
(Ib/MWh)
Greenhouse Gases
(lb C02eq/MWh)
kW
Biogas
Flow in
(SCFM)
Gas Flow in
(MMBtu/h)
(%)
Heat Rate
(Btu/kWh)
($/MWh)
NOx
CO
PM
voc
sox
ch4
C02*
n2o
ch4
C02*
N20
100
40
1.4
23.9
14,300
89.8
0.61
2.16
0.20
0.23
0.0429
11.99
2,737
0.027
408
2,737
8.2
150
56
2.0
25.5
13,400
83.0
0.57
2.02
0.19
0.21
0.0402
11.23
2,564
0.026
382
2,564
7.7
190
68
2.5
26.4
12,900
79.5
0.55
1.95
0.18
0.21
0.0388
10.83
2,473
0.025
368
2,473
7.4
220
77
2.8
27.0
12,600
77.4
0.54
1.91
0.18
0.20
0.0379
10.60
2,420
0.024
360
2,420
7.2
300
101
3.6
28.2
12,100
73.3
0.52
1.82
0.17
0.19
0.0363
10.14
2,315
0.023
345
2,315
6.9
420
135
4.9
29.5
11,600
69.2
0.49
1.74
0.16
0.18
0.0347
9.68
2,210
0.022
329
2,210
6.6
600
184
6.6
31.0
11,000
65.2
0.47
1.66
0.15
0.18
0.0331
9.24
2,109
0.021
314
2,109
6.3
800
236
8.5
32.1
10,600
62.2
0.46
1.60
0.15
0.17
0.0319
8.91
2,034
0.020
303
2,034
6.1
1000
287
10.3
33.0
10,300
59.4
0.44
1.56
0.14
0.17
0.0310
8.67
1,980
0.020
295
1,980
5.9
1550
423
15.2
34.7
9,800
54.3
0.42
1.48
0.14
0.16
0.0295
8.24
1,881
0.019
280
1,881
5.6
2000
531
19.1
35.7
9,600
51.6
0.41
1.44
0.13
0.15
0.0287
8.01
1,828
0.018
272
1,828
5.5
3000
762
27.4
37.3
9,100
47.6
0.39
1.38
0.13
0.15
0.0274
7.66
1,749
0.018
261
1,749
5.2
*
biogenic CO2 emissions
Emission Factor (Ib/MMBtu)
GHG Emission Factors
(Ib/MMBtu)
GWP100
Rule
1110.2
ST Aves.
(SCR/CatOx)
(AP
42)
ST Aves. (SCR/CatOx)
ch4
C02*
N20
ch4
C02*
N20
NOx
CO
PM
VOC
sox
ST Aves. = Source Test Averages
0.043
0.151
0.014
0.016
0.003
0.838
191.3
0.00192
34
1
298
-------
Fuel Cells
Capacity
Energy
Efficiency
(%, HHV
basis)
Levelized
Emissions (Ib/MWh)
GHG (Ib/MWh)
GHG
(lb C02eq/MWh)
kW
Gas
Flow in
(SCFM)
Gas Flow in
(MMBtu/h)
Cost
|S/MWh)
NOx
CO
PM
VOC
sox
ch4
C02 *
N20
ch4
C02 *
N20
200
42
1.5
45.0
164
0.02
0.070
0.01
0.06
0.001
0.019
1451
0.002
0.66
1451
0.58
300
63
2.3
45.0
150
0.02
0.07
0.01
0.06
0.001
0.019
1451
0.002
0.66
1451
0.58
500
105
3.8
45.0
135
0.02
0.07
0.01
0.06
0.001
0.019
1451
0.002
0.66
1451
0.58
800
169
6.1
45.0
122
0.02
0.07
0.01
0.06
0.001
0.019
1451
0.002
0.66
1451
0.58
1000
211
7.6
45.0
116
0.02
0.07
0.01
0.06
0.001
0.019
1451
0.002
0.66
1451
0.58
1400
295
10.6
45.0
108
0.02
0.07
0.01
0.06
0.001
0.019
1451
0.002
0.66
1451
0.58
6000
1264
45.5
45.0
79
0.02
0.07
0.01
0.06
0.001
0.019
1451
0.002
0.66
1451
0.58
Emission Factor (Ib/MMBtu)
Emission Factor
(Ib/MMBtu)
GWP100
NOx
CO
PM
VOC
SOx
ch4
C02*
N20
ch4
C02*
N20
0.0026
0.0092
0.00132
0.0081
0.0001
0.0026
191.3
0.00026
34
1
298
* Biogenic CO2 emissions
-------
RNG with On-site Fueling
Biogas Flow input
Methane
recovery
(%)
RNG
-uel Product Output
(SCFM)
(MMBtu/h)
(SCFM)
(MMBtu/h)
(GGE/day)
50
1.8
70
22.1
1.3
241
100
3.6
70
44
2.5
482
200
7.2
70
88
5
963
1600
57.6
85
859
49
9,359
Emissions (lb/day)
NOx
CO
PM
VOC
sox
(SCFM)
50
0.71
0.59
0.15
0.08
0.50
100
1.43
1.18
0.31
0.16
1.01
200
2.86
2.36
0.62
0.31
2.02
1600
11.04
9.13
2.39
1.21
7.79
Emission Factor (Ib/MMBtu input to process)
NOx
CO
PM
VOC
sox
70% CH4
Recovery:
0.0165
0.0137
0.0036
0.0018
0.0117
85% CH4
Recovery:
0.008
0.007
0.002
0.001
0.006
*Biogenic CO2 emissions
Levelized Cost
($/MM
Btu gas
input)
($/MMBtu
output)
$/gallons
gasoline
eq.
$/gallons
diesel eq.
12.8
18.3
2.42
2.75
9.0
12.8
1.69
1.92
6.5
9.3
1.23
1.40
3.4
4.0
0.53
0.60
Greenhouse Gases (lb/day)
Greenhouse Gases
(lb C02eq/day)
ch4
C02*
N20
ch4
C02*
N20
18.9
4,599
0.03
642
4,599
9
37.8
9,197
0.06
1,280
9,197
18
75.5
18,395
0.12
2,570
18,395
36
589.9
122,125
0.47
20,100
122,125
140
(Ib/MMBtu input to
process)
GWP100
ch4
C02*
N20
0.44
106.5
0.00070
ch4
C02*
N20
0.43
88.3
0.00034
34
1
298
71
-------
Upgrade & Pipeline Injection
Biogas Flow Input
Product Gas Flow
Levelized Cost
Emissions (lb/day)
Greenhouse Gases (lb/day)
Greenhouse Gas
(lb CC>2eq/day
es
(SCFM)
(MMBtu/h)
(SCFM)
(MMBtu/h)
($/MMBtu
gas input)
($/MMBtu
output)
NOx
CO
PM
voc
SOx
ch4
C02*
N20
ch4
C02*
N20
50
1.8
27.5
1.6
24.7
27.4
0.22
0.18
0.05
0.02
0.16
18.8
3,721
0.009
640
3,721
3
75
2.7
41
2.4
21.5
23.9
0.33
0.28
0.07
0.04
0.23
28.2
5,582
0.014
960
5,582
4
100
3.6
55
3.2
19.6
21.8
0.44
0.37
0.10
0.05
0.31
37.7
7,443
0.019
1,280
7,443
6
150
5.4
83
4.9
17.1
19.0
0.67
0.55
0.14
0.07
0.47
56.5
11,164
0.028
1,920
11,164
8
300
10.8
165
9.7
13.6
15.1
1.3
1.1
0.3
0.1
0.9
113
22,328
0.057
3,840
22,328
17
600
21.6
331
19.4
10.8
12.0
2.7
2.2
0.6
0.3
1.9
226
44,656
0.113
7,680
44,656
34
1200
43.2
661
38.9
8.6
9.5
5.3
4.4
1.2
0.6
3.8
452
89,313
0.226
15,400
89,313
67
2300
82.8
1267
74.5
6.9
7.7
10.2
8.4
2.2
1.1
7.2
866
171,182
0.434
29,400
171,182
129
Emission Factor (Ib/MMBtu input to
process)
(Ib/MMBtu input to
process)
GWP100
NOx
CO
PM
VOC
SOx
ch4
C02*
N20
ch4
C02*
N20
0.0051
0.0042
0.0011
0.0006
0.0036
0.4358
86.1
0.00022
34
1
298
* Biogenic CO2 emissions
-------
Flare
Capacity
Levelized
Emissions (lb/day)
Greenhouse Gases
Cost
Green
nouse Gases
(lb CCheq/day)
Gas
Flow
input
(SCFM)
Gas Flow
input
(MMBtu/h)
($/MMBtu)
Input
NOx
CO
PM
VOC
sox
ch4
C02*
l\l20
ch4
C02*
l\l20
17
0.6
1.25
0.8
0.7
0.2
0.1
0.6
1.0
2,755
0.03
34
2,755
10.4
28
1
1.10
1.4
1.1
0.3
0.1
1.0
1.7
4,592
0.06
57
4,592
17.3
56
2
0.93
2.7
2.3
0.6
0.3
1.9
3.3
9,184
0.12
114
9,184
34.7
139
5
0.74
6.8
5.7
1.5
0.7
4.8
8.4
22,961
0.29
284
22,961
86.7
194
7
0.68
9.6
7.9
2.1
1.0
6.8
11.7
32,145
0.41
398
32,145
121.4
278
10
0.62
13.7
11.3
3.0
1.5
9.7
16.7
45,922
0.58
568
45,922
173.4
417
15
0.56
20.5
17.0
4.5
2.2
14.5
25.1
68,883
0.87
853
68,883
260.2
556
20
0.52
27.4
22.6
5.9
3.0
19.3
33.4
91,844
1.16
1,140
91,844
346.9
833
30
0.47
41.1
34.0
8.9
4.5
29.0
50.2
137,766
1.75
1,710
137,766
520.3
Emission Factor (Ib/MMBtu)
Emission Factor (Ib/MMBtu)
GWP100
NOx
CO
PM
VOC
SOx
ch4
C02*
N20
ch4
C02*
N20
0.0570
0.0472
0.01236
0.0062
0.0403
0.070
191.3
0.00243
34
1
298
*Biogenic CO2 emissions
-------
Appendix B- Grants & Other Financial Incentives
Compilation of Key Funding Sources
- Guide to Federal Financing for Energy Efficiency and Clean Energy Development September 2014
- Database of State Incentives for Renewable and Efficiency
- EPA Region 9's Sustainable Water Infrastructure
Federal & California Agency-Specific Funding
Funding Agency Program Title
Bav Area Air Qualitv Management District
Grant Funding
Cal Recycle
Greenhouse Gas (GHG) Reduction Loan Program
Cal Recycle
Organics Grant Program
CALFED
CALFED Grants and Contracts
California Air Resources Board
Carl Mover Memorial Air Qualitv Standards Attainment Program
California Air Resources Board
Low Carbon Transportation Investments and Air Qualitv Improvement
Program (AQIP)
California Air Resources Board
Low Carbon Fuel Standard
California Air Resources Board
Cap and Trade Auction Proceeds
California Center for Sustainable Energy
California Center for Sustainable Energv - Self Generation Incentive
Program
California Center for Sustainable Energy
California Center for Sustainable Energv - Border Energv Savings Program
California Dept. of Food and Agriculture
Dairy Digester Research and Development Program
California Energy Commission
California Energy Commission- Clean Energy Manufacturing Program
California Energy Commission
Energv Efficiency Financing (1% loans: PON 13-401)
California Energy Commission
Alternative and Renewable Fuel and Vehicle Technology Program (AB 118)
California Energy Commission
Electric Program Investment Charge (EPIC) Program
California Public Utilities Commission
California Public Utilities Commission - Solar Incentives
California Public Utilities Commission
California Public Utilities Commission Qualifying Facility Program
California Public Utilities Commission
Self-Generation Incentive Program
California Statewide Communities
Development Authority
California First (PACE Financing)
Infrastructure Bank
Infrastructure State Revolving Fund Program
PG&E
Pacific Gas & Electric Self-Generation Incentive Program
74
-------
Sacramento Metropolitan Air Qualitv
Off- & On-Road Grant Programs
Management District
SJVAPCD
Grants and incentives
SJVAPCD
Technology Advancement Program
SDG&E
San Diego Gas & Electric Companv Rebates and Incentives
SMAQMD
Grant program
SMUD
Sacramento Municipal Utilitv District Business Rebates and Incentives
SCAQMD
Grants and Bids
Southern California Edison
Southern California Edison Self-Generation Incentive Program
Southern California Gas Company
Southern California Gas Companv Self-Generation Incentive Program
Southern California Gas Company
Southern California Gas Companv Water Supplv and Treatment
State Water Resource Control Board
Clean Water State Revolving Fund
U.S. Bureau of Reclamation
Svstem Optimization Review Grants
U.S. Bureau of Reclamation
Water & Energv Efficiency Grants
U.S. Department of Agriculture
Advanced Biofuel Pavment Program
U.S. Department of Agriculture
Biorefinerv Assistance Program
U.S. Department of Agriculture
High Energv Cost Grant Program
U.S. Department of Agriculture
Repowering Assistance Program
U.S. Department of Agriculture
Rural Utilities Service Electric Program
U.S. Department of Agriculture
Water and Environmental Programs
U.S. Department of Agriculture
Rural Energv for America Program Renewable Energv Svstems & Energv
Efficiency Improvement Loans & Grants
U.S. Department of Energy
Federal Funding for State and Local Clean Energv Programs
U.S. Department of Energy
Loan Guarantee Program
U.S. Department of Energy
Renewable Energv Production Incentive
U.S. Department of Energy
Technical Assistance Program (TAP)
U.S. Environmental Protection Agency
Renewable Fuel Program
U.S. Environmental Protection Agency
Diesel Emissions Reduction Program
U.S. Internal Revenue Service
Renewable Electricity Production Tax Credit
U.S. Small Business Administration
Small Business Innovation Research
75
-------
Appendix C- Source Test Data
Source Tests - Microturbines
Primemover
Emissions equip,
notes
Source
Test Date
AQMD
Power during
test (kW)
Emissions (Ibs/hr)
Emissions (Ibs/MMBtu)
NOx
CO
S02
voc
NOx
CO
S02
VOC
City of Millbrae 250 kW
microturbine fueled w/ digester
gas(2007)
-
Jan, 2007
BAAQMD
250
0.063
0.04
0.008
0.0167
0.0106
0.00212
Ralph's Groceries Ingersoll Rand
250 kW microturbine # 1
no post combustion
emissions
treatment
Feb., 2013
SCAQMD
250
0.058
0.088
0.23
0.06
0.0149
0.0221
0.0590
0.0154
Ralph's Groceries Ingersoll Rand
250 kW microturbine #2
no post combustion
emissions
treatment
Feb., 2013
SCAQMD
250
0.06
0.092
0.27
0.03
0.0154
0.0231
0.0692
0.0077
Ralph's Groceries Ingersoll Rand
250 kW microturbine #3
no post combustion
emissions
treatment
Feb., 2013
SCAQMD
250
0.061
0.093
0.27
0.07
0.0156
0.0233
0.0692
0.0179
Source Tests - Flares
Equipment Descriptions
Source
Test Date
AQMD
Flow/Cap
Energy in
Fuel
(Btu/scfl
Fuel flow
(SCFM)
MMBtu/h
Emissions (Ibs/hr)
Emissions (Ibs/MMBtu)
NOx
CO
S02
VOC
PM
NOx
CO
S02
VOC
PM
Eastern Muni / San Jacinto
Valley Water Reclamation -
Digester Gas Flare
Jan-08
SCAQMD
18 MMBtu
622
165
6.16
0.365
0.301
0.129
0.0425
0.092
0.059
0.049
0.021
0.007
0.015
Eastern Muni / Moreno
Valley - Digester Gas Flare
May-12
SCAQMD
1.7 MMBti
192
25
0.29
0.0032
0.003
0.09
0.0005
0.02
0.011
0.010
0.313
0.002
0.069
Tulare WPCF _Gigestergas
flare
Sep-13
SJVAPC
12.4
631
37
1.40
0.09
0.28
0.003
0.064
0.200
0.002
Lamb Canyon Landfill
May-07
sCAQMD
430
211
5.44
0.3
0.036
0.037
0.035
0.055
0.007
0.007
0.006
Source Tests - Fuel Cells
Emissions equip, notes
Source
Test Date
AQMD
Capacity
(kW)
Fuel flow
(SCFM)
Emissions (Ibs/hr)
Emissions (Ibs/MMBtu)
NOx
CO
S02
VOC
NOx
CO
S02
VOC
Fuel Cell - Tulare City WWTP
Permit only
SJVAPCD
300
63
0.006
0.015
0.0003
0.006
0.0026
0.007
0.00013
0.003
Eastern Muni Water District (2 x 300 kW
fuel cells)
Permit only
SCAQMD
600
126
0.0015
0.042
0.0006
0.08
0.00033
0.009
0.00013
0.018
Moreno Valley RWQRF Fuel Cell Energy
DFC300MA
Mar-09
SCAQMD
250
53
0.005
0.005
0.008
0.0028
0.003
0.004
76
-------
Source Tests - Gas Turbines
Primemover
Emissions equip, notes
Source
Test
Date
AQMD
Power
during
test (kW)
Emissions (Ibs/hr)
Emissions (Ibs/MMBtu)
NOx
CO
S02
voc
NOx
CO
S02
VOC
OS-4529 Gas Turbine Altamont Landfill
S-6
No apparent emission
control, LFG
Feb-13
BAAQMD
3100
5.36
3.58
0.19
0.3
0.116
0.078
0.004
0.007
Altamont Turbine S-7
No apparent emission
control, LFG
Feb-13
BAAQMD
3100
5.29
3.67
0.24
0.3
0.116
0.081
0.005
0.007
Calabasas Solar Mercury 50
recuperative,, 4.5 MW, Turbine A
"Low NOX", 2004 era, LFG
2010
SCAQMD
4095
1.5
0.177
3.1
0.6
0.031
0.004
0.064
0.012
Calabasas Solar Mercury 50
recuperative,, 4.5 MW, Turbine B
"Low NOX", 2004 era, LFG
2010
SCAQMD
4391
1.3
0.164
2.6
0.28
0.031
0.004
0.062
0.007
Calabasas Solar Mercury 50
recuperative,, 4.5 MW, Turbine C
"Low NOX", 2004 era, LFG
2010
SCAQMD
4391
1.3
0.143
2.6
0.17
0.031
0.003
0.062
0.004
Fresno/Clovis RWRF 2x 3.3 GT w/ ~l-2
MW steam turbine. Water injection
and SCR equipped. ~ 36% volumetric
fuel flow is natural gas. Digester gas is
upgraded to about 950 Btu/scf
SCR, WWTP
2013
Turbine 1
SJVAPCD
4500
0.766
0.621
-
-
0.013
0.011
Fresno/Clovis RWRF 2x 3.3 GT w/ ~l-2
MW steam turbine. Water injection
and SCR equipped.
SCR, WWTP
2013
Turbine 2
SJVAPCD
4680
0.602
1.181
-
-
0.010
0.020
Fresno/Clovis RWRF 2x 3.3 GT w/ ~l-2
MW steam turbine. Water injection
and SCR equipped.
SCR, WWTP
2012
Turbine 1
SJVAPCD
3487
0.43
0.37
0.0095
0.008
Fresno/Clovis
SCR, WWTP
2012
Turbine 2
SJVAPCD
4280
0.51
1.1
0.0092
0.020
EBMUD Solar Mercury 50 Ultra-lean
premix recuperative, "Low-NOx"
burner, 4.5 MW, 44.5 MMBtu/h
"Advanced low-Nox
burner", WWTP
BAAQMD
4500
0.59
0.2
0.2
0.03
0.014
0.005
0.005
0.001
77
-------
Source Tests - Reciprocating Engines
Primemover
Emissions equip, notes
Source Test
Date
AQMD
Power
during
Emissions (Ibs/hr)
Emissions (Ibs/MMBtu)
Emissions (Ibs/MWh)
NOx
CO
S02
VOC
NOx
CO
S02
VOC
NOx
CO
S02
VOC
Reciprocating engine, 2980 hp, 13000 cu in,
Co-generation, Multi-Fuel Cogeneration
Engine #1EBMUD S-37
No apparent emission
control, WWTP digester gas
5/21/2013
BAAQMD
1940
1.5
10.2
0.3
0.4
0.079
0.537
0.016
0.021
0.77
5.26
0.15
0.21
Reciprocating engine, 2980 hp, 13000 cu in,
Co-generation, Multi-Fuel Cogeneration
Engine #3 EBMUD S-39
No apparent emission
control, WWTP digester gas
6/12/2013
BAAQMD
1917
1.7
9.6
0.14
1.7
0.081
0.457
0.007
0.081
0.89
5.01
0.07
0.89
Reciprocating engine, 2980 hp, 13000 cu in,
Co-generation, Multi-Fuel Cogeneration
Engine #2 EBMUD S-38
No apparent emission
control, WWTP digester gas
9/19/2013
BAAQMD
2180
2.8
11
0.78
2.1
0.122
0.478
0.034
0.091
1.28
5.05
0.36
0.96
Reciprocating engine, 706 hp, Waukesha,
3520cu in 225, Cogen Engine-2, Dublin San
Ramon Services District, Plant #1371,
No apparent emission
control, WWTP digester gas
7/25/2013
BAAQMD
400
0.39
2.5
0.021
0.3
0.087
0.561
0.005
0.067
0.98
6.25
0.05
0.75
Fairfield Suisun Sewer S-54 Reciprocating
engine, 1268 hp, Waukesha, 7040 cu in 287
Cogen Engine #3 (Pad 4), Nat and Dig Gas,
900k W
No apparent emission
control, WWTP digester gas
8/17/2012
BAAQMD
844
1.10
4.83
0.071
0.20
0.138
0.604
0.009
0.024
1.31
5.73
0.08
0.23
Fairfield Suisun Sewer S-54 Reciprocating
engine, 1268 hp, Waukesha, 7040 cu in 287
Cogen Engine #3 (Pad 4), Nat and Dig Gas,
900k W
No apparent emission
control, WWTP digester gas
8/15/2013
BAAQMD
725
0.74
5.80
0.154
1.25
0.105
0.819
0.022
0.176
1.02
8.01
0.21
1.72
Fairfield Suisun Sewer S-3, Reciprocating
engine, 800 hp, 6597 cu in, Cogen Engine #2,
Digester Gas Fired
No apparent emission
control, WWTP digester gas
5/17/2012
BAAQMD
370
0.93
2.65
0.142
0.03
0.167
0.474
0.025
0.005
2.51
7.15
0.38
0.08
Fairfield Suisun Sewer S-3, Reciprocating
engine, 800 hp, 6597 cu in, Cogen Engine #2,
Digester Gas Fired
No apparent emission
control, WWTP digester gas
5/28/2013
BAAQMD
354
0.81
2.57
0.317
0.15
0.1512
0.480
0.059
0.027
2.28
7.25
0.89
0.41
Sunnyvale Water Pollution Control S-15
Reciprocating engine, 1130 hp, Caterpillar,
5110 cu in 221, Engine/Generator No. 2
No apparent emission
control, WWTP digester gas
2/28/2012
BAAQMD
690
1.05
3.9
0.533
0.23
0.1150
0.427
0.058
0.026
1.52
5.65
0.77
0.34
Sunnyvale Water Pollution Control S-15
Reciprocating engine, 1130 hp, Caterpillar,
5110 cu in 221, Engine/Generator No. 2
No apparent emission
control, WWTP digester gas
2/10/2014
BAAQMD
604
1.77
2.66
0.8
0.28
0.238
0.357
0.107
0.038
2.93
4.40
1.32
0.46
Sunnyvale Water Pollution Control S-14
Reciprocating engine, 1130 hp, Caterpillar,
5110 cu in 221, Engine/Generator No. 1
No apparent emission
control, WWTP digester gas
3/1/2012
BAAQMD
656
1.16
4.25
0.6
0.14
0.128
0.467
0.066
0.016
1.77
6.48
Sunnyvale Water Pollution Control S-14
Reciprocating engine, 1130 hp, Caterpillar,
5110 cu in 221, Engine/Generator No. 1
No apparent emission
control, WWTP digester gas
2/10/2014
BAAQMD
607
1.19
3.89
0.58
0.32
0.152
0.496
0.074
0.041
1.96
6.41
San Leandro Water Pollution Control : S-14-
Reciprocating engine, 148 hp, MAN, 419 cu
in, Co-generation-Biogas Fired IC Engine
No apparent emission
control, WWTP digester gas
5/18/2010
BAAQMD
105
0.26
0.22
0.04
0.291
0.248
0.045
2.48
2.10
San Leandro Water Pollution Control : S-15 -
Reciprocating engine, 148 hp, MAN, 419 cu
in, Co-generation-Biogas Fired IC Engine
No apparent emission
control, WWTP digester gas
5/18/2010
BAAQMD
105
0.29
0.29
0.05
0.254
0.255
0.044
2.76
2.76
San Leandro Water Pollution Control : S-16 -
Reciprocating engine, 148 hp, MAN, 419 cu
in, Co-generation-Biogas Fired IC Engine
No apparent emission
control, WWTP digester gas
5/18/2010
BAAQMD
105
0.24
0.31
0.05
0.225
0.292
0.047
2.29
2.95
SFPUC, S-26 Reciprocating engine, 773 hp,
Waukesha, 3520cu, Internal Combustion
Engine Generator No. 1
No apparent emission
control, WWTP digester gas
7/23/2012
BAAQMD
460
0.175
2.62
0.22
0.062
0.913
0.077
0.38
5.70
SFPUC, S-26 Reciprocating engine, 773 hp,
Waukesha, 3520cu, Internal Combustion
Engine Generator No. 2
No apparent emission
control, WWTP digester gas
9/24/2013
BAAQMD
482
0.35
2.91
0.02
0.28
0.086
0.724
0.005
0.069
0.73
6.03
Bakersfield WWTP: 577 BHP Waukesha
digester gas lean burn engine #2
5/28/2013
SJVAPCD
400
0.079
0.380
0.003
Bakersfield WWTP: 577 BHP Waukesha
digester gas lean burn engine #2
6/10/2011
SJVAPCD
400
0.118
0.321
0.004
Bakersfield WWTP: 577 BHP Waukesha
digester gas lean burn engine #2
11/2/2009
SJVAPCD
400
0.074
0.335
0.003
Visalia Landfill 1150 HP Lean Burn CAT
G3516TA Landfill Gas. S-2890-1-6
12/14/2010
SJVAPCD
737
1.23
6.36
0.2
0.119
0.611
0.019
1.67
Tulare Waste Water Plant 670 BHP
WAUKESHA MODEL L5108GL BIOGAS-FIRED
LEAN BURN IC ENGIN E WITH H2S SCRUBBER
POWERING AN ELECTRIC GENERATOR
12/3/2013
SJVAPCD
450
0.183
0.608
0.011
Yolo County Landfill 550 kWCat. El, P-78-98
Airfuel ratio controller
3/26/2013
YSAQMD
550
0.761
3.92
0.14
0.084
0.425
0.032
1.38
Yolo County Landfill 1306 BHP Cat. G-3516
900 kW E2 (4A, P-78-98
Airfuel ratio control ler
3/6/2013
YSAQMD
893
2.259
7.63
0.12
0.163
0.540
0.016
2.53
Yolo County Landfill 550 kWCat. E4, P-78-98
Airfuel ratio control ler
3/26/2013
YSAQMD
550
1.120
0.120
0.375
0.030
2.04
Yolo County Landfill 840 kW
Airfuel ratio control ler
2/28/2013
YSAQMD
840
1.340
5.37
0.08
0.135
0.540
0.016
1.60
Davis WWTP 110 BHP digester gas Cat G342 -
3/20/2013
YSAQMD
75
0.1082
0.096
0.531
1.44
Hay Road Landfill - 2233 BHP Cat G3520C- 1650
kW
Airfuel ratio control ler
YSAQMD
1600
1.11
9.94
0.04
0.066
0.590
0.003
0.69
Waukesha, VGF48GL (San Bernard. Water
Dept. Cogen #1: at least 2 identical systems)
2005 or earl ire appl. #431476
2006
SCAQMD
620
0.450
0.22
0.066
0.032
0.73
0.35
Waukesha, VGF48GL (San Bernard. Water
Dept. Cogen #2: at least 2 identical systems)
2005 or earl ire appl. #431477
2006
SCAQMD
620
0.380
0.16
0.056
0.023
0.61
0.26
Fiscalini Dairy: 1067 BHP Guascor SFGLD-560
Engine w SCR - -750 kW gen
SCR
2012
SJVAPCD
350
0.088
1.068
0.080
0.022
0.267
0.020
0.25
3.05
0.23
Fiscalini Dairy: 1067 BHP Guascor SFGLD-560
Engine w SCR - -750 kW gen
SCR/ox cat
2013
SJVAPCD
250
0.117
0.699
0.001
0.038
0.226
0.00027
0.47
2.79
0.00
Fiscalini Dairy: 1067 BHP Guascor SFGLD-560
Engine w SCR - -750 kW gen
SCR/ox cat
2014
SJVAPCD
150
0.015
0.395
0.000
0.010
0.255
0.00027
0.10
2.63
0.00
#1: MWM TCG 2016 V16 w/ SCR and Ox
Catalyst
SCR/ox cat
2015
Mojave
Desert
800
0.577
0.011
0.0002
0.222
0.084
0.002
0.00003
0.03223
#1: MWM TCG 2016 V16 w/ SCR and Ox
Catalyst
SCR/ox cat
2015
800
0.213
0.031
0.0002
0.17
0.034
0.005
0.00003
0.02721
78
-------
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