EPA-600/R-95-089
July 1995
METHODOLOGIES FOR QUANTIFYING
POLLUTION PREVENTION BENEFITS FROM
LANDFILL GAS CONTROL AND UTILIZATION
by
Stephen M. Roe, Paula G. Fields, and Renee E. Coad
E.H. Pechan & Associates, Inc.
2880 Sunrise Blvd., Suite 220
Rancho Cordova, CA 95742
EPA Contract No. 68-D1-0146
Work Assignment No. 2/034
EPA Project Officer:
Susan A.Thorneloe
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
Prepared for:
U.S. Environmental Protection Agency
Office of Research and Development
Washinaton, DC 20460
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before com/
1, REPORT NO.
EPA-600/R-95-089
2.
4. TITLE AND SUBTITLE
Methodologies for Quantifying Pollution Prevention
Benefits from Landfill Gas Control and Utilization
5. REPORT DATE
July 1995
6. PERFORMING ORGANIZATION CODE
7. AUTHORtSl
S. M. Hoe, P. G. Fields, and R. Goad
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
E.H. Pechan and Associates, Inc.
2880 Sunrise Boulevard, Suite 220
Raneho Cordova, California 95742
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-Dl-0146, Task 2/034
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory*
Research Triangle Park, NC 27T11
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 11/93 -'10/94
14. SPONSORING AGENCY CODE
EPA/600/13
is. supplementary notes project officer is Susan A. Thorneloe, Mail Drop 63, 919/
541-2709. (*) Redesignated Air Pollution Prevention and Control Division.
is. abstract ,
The report describes developing emission factors for controlled pri-
mary pollutants (e. g. , nonmethane organic compounds) and secondary air pollutants
(e. g., carbon monoxide). The report addresses the following criteria air pollutants
and greenhouse gases: carbon dioxide, carbon monoxide, methane, nitrogen oxides,
nonmethane organic compounds, and sulfur dioxide. For this report, primary pollu-
tants are those contained in landfill gas (LFG), and secondary pollutants are those re-
sulting from the combustion of LFG by control or utilization equipment. Data are in-
cluded that allow an analyst to convert emission factors to units that allow for direct
comparison with energy alternatives (e.g., pounds of a pollutant released per kilo-
watt-hour of electricity produced). (NOTE: A combination of mass balance methods
and emission factors based on source data can be used to compare air pollution po-
tential between different LFG control or utilization options. These methods and emis-
sion factors can also be used to compare between LFG utilization projects and the
more established energy alternatives (e.g., coal, natural gas). Uncontrolled and
controlled LFG emission inventories can also be prepared to assess the benefits of
LFG control or utilization. LFG flaring is the only control option addressed in this
report, but three utilization options are included.)
17.
KEY WORDS AND DOCUMENT ANALYSIS
2. DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Pollution Control
13B
Earth Fills
Stationary Sources
13 C
Gases
Landfill Gas
07D
Emission
14G
Estimating
Energy
Inventories
15 E
18, DISTRIBUTION STATEMENT
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
47
Release to Public
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify thai the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
ABSTRACT
A combination of mass balance methods and emission factors based on source data can be used to make
comparisons in air pollution potential between different landfill gas (LFG) control or utilization options.
These methods and emission factors can also be used to make comparisons between LFG utilization
projects and the more established energy alternatives (e.g., coal, natural gas). Uncontrolled and controlled
LFG emission inventories can also be prepared to assess the benefits of LFG control or utilization. LFG
flaring is the only control option addressed in this report, while the utilization options include reciprocating
internal combustion (RIC) engines, steam and gas turbines, and boilers.
This report describes the development of emission factors for controlled primary pollutants (e.g.,
nonmethane organic compounds) ami secondary air pollutants (e.g., carbon monoxide). The following
criteria air pollutants and greenhouse gases are addressed in this document: nonmethane organic
compounds, carbon monoxide, sulfur dioxide, nitrogen oxides, carbon dioxide, and methane. For this
report, primary pollutants are those contained in LFG and secondary pollutants are those resulting from
the combustion of LFG by control or utilization equipment. Data are included that allow an analyst to
convert emission factors to units that allow for direct comparison with the energy alternatives mentioned
above (e.g., pounds of a pollutant released per kilowatt-hour of electricity produced).
Methods to prepare uncontrolled and controlled LFG emission inventories are also included. The methods
describe the mass balance techniques needed to estimate emissions of the primary and some secondary
LFG pollutants and the use of secondary pollutant emission factors for those species that can not be
estimated by mass balance.
An example is included that demonstrates the methods and use of the data presented in the report. The
example shows how emission factors are developed for LFG flare control and an LFG utilization with an
RIC engine, a gas turbine, and a boiler. Comparison emission factors are developed for a coaJ-fired steam
power plant, a natural gas turbine power plant, and an industrial boiler. An emission inventory of an
uncontrolled landfill is also developed and compared to emission inventories projected for the landfill
following installation of an LFG flare, RIC engine plant, gas turbine plant, or boiler.
ii
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TABLE OF CONTENTS
ABSTRACT ii
TABLES iv
ACKNOWLEDGEMENTS v
ABBREVIATIONS vi
SYMBOLS vi
CONVERSIONS vii
1. INTRODUCTION 1
1.1 Background 1
1.2 Purpose 1
2. ASSESSING UNCONTROLLED LFG EMISSIONS 3
3. DETERMINING CONTROLLED LFG EMISSION FACTORS AND EMISSION RATES 4
3.1 Carbon Monoxide and Nitrogen Oxides 5
3.2 Nonmethane Organic Compounds 8
3.3 Sulfur Dioxide 9
3.4 Methane 10
3.5 Carbon Dioxide 10
4. EXAMPLE ASSESSMENT OF LFG CONTROL AND UTILIZATION 12
4.1 Uncontrolled Landfill Emissions 12
4.2 Controlled Landfill Gas Emissions 14
4.2.1 Emissions Resulting from LFG Control Using a Flare 14
4.2.2 Emissions Resulting from LFG Utilization Using a RIC Engine 18
4.2.3 Emissions Resulting from LFG Utilization Using a Gas Turbine 21
4.2.4 Emissions Resulting from LFG Control Using a Boiler 24
4.3 Deriving Emissions for Alternative Energy Sources 26
4.3.1 Coal-Fired Steam Power Plant 28
4.3.2 Natural Gas-Fired Turbine 29
4.3.3 Industrial Boiler 30
4.4 Example LFG Control and Utilization Comparison Summary 32
5. ISSUES REQUIRING ADDITIONAL ANALYSIS 36
REFERENCES 37
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TABLES
1. DEFAULT LANDFILL PARAMETERS 5
2. DEFAULT LFG EMISSION FACTORS FOR CO AND NOx 6
3. DEFAULT FACILITY HEAT RATES FOR LFG UTILIZATION 8
4. EXAMPLE LANDFILL OPERATING PARAMETERS 12
5. LFG CONSTITUENT CONCENTRATIONS 13
6. EXAMPLE ASSESSMENT: ANNUAL UNCONTROLLED EMISSIONS 13
7. FLARE EXAMPLE: SUMMARY OF CONTROLLED AIR POLLUTANT EMISSION
FACTORS AND EMISSION RATES 15
8. RIC ENGINE EXAMPLE: SUMMARY OF CONTROLLED AIR POLLUTANT EMISSION
FACTORS AND EMISSION RATES 19
9. GAS TURBINE EXAMPLE: SUMMARY OF CONTROLLED AIR POLLUTANT EMISSION
FACTORS AND EMISSION RATES 23
10. BOILER EXAMPLE: SUMMARY OF CONTROLLED AIR POLLUTANT EMISSION
FACTORS AND EMISSION RATES 25
11. EMISSION FACTOR CONVERSION DATA AND FUEL PARAMETERS 27
12. DEFAULT PLANT HEAT RATES FOR COMPARISON TECHNOLOGIES 28
13. COAL-FIRED STEAM POWER PLANT: SUMMARY OF EMISSION FACTORS AND
EMISSION RATES 29
14. NATURAL GAS TURBINE POWER PLANT: SUMMARY OF EMISSION FACTORS AND
EMISSION RATES 30
15. NATURAL GAS-FIRED BOILER: SUMMARY OF EMISSION FACTORS AND EMISSION
RATES 31
16. DISTILLATE OIL-FIRED BOILER: SUMMARY OF EMISSION FACTORS AND EMISSION
RATES 32
17. COMPARISON OF LFG UTILIZATION AND ALTERNATIVE ENERGY SOURCE
EMISSION FACTORS 33
18. COMPARISON OF ANNUAL EMISSIONS: LFG CONTROL/UTILIZATION AND
ALTERNATIVE ENERGY SOURCES 34
19. COMPARISON OF LFG UTILIZATION AND ALTERNATIVE ENERGY SOURCE
EMISSION FACTORS 34
20. COMPARISON OF ANNUAL EMISSIONS: BOILER LFG CONTROL AND ALTERNATIVE
ENERGY SOURCES 35
21. COMPARISON OF ANNUAL EMISSIONS: UNCONTROLLED VERSUS CONTROLLED
LANDFILL 35
iv
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ACKNOWLEDGEMENTS
The authors are particularly grateful for the guidance provided by the EPA Project Officer, Susan
Thorneloe. The authors would also like to make the following acknowledgements to those in both the
public and private sectors who provided technical data and/or reviewed the methods presented in this
report:
Chuck Anderson of Rust Environment and Infrastructure
Dave Byrnes of the San Diego County Air Pollution Control District
John Pacey of FHC, Inc.
Rick Oakley of Browning-Ferris Industries
David Solomon, Mark Najarian, and Ron Meyers of EPA's Office of Air Quality Planning & Standards
George Jansen of Laidlaw Environmental Sen/ices
Stan Drake of Energy Tactics, Inc.
Kathleen Hogan and Ed Coe of EPA's Office of Air & Radiation
Randy Strait and Michiel Doom of E.H. Pechan & Associates, Inc., Durham, NC
v
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ABBREVIATIONS
AEERL
Air and Energy Engineering Research Laboratory
Btu
British thermal unit
CAA
Clean Air Act
CFC
Chlorofluorocarbon(s)
DOE
U.S. Department of Energy
EF
Emission factor
EPA
U.S. Environmental Protection Agency
eq.
Equation
ESP
Electrostatic precipitator
ft
Foot or feet
GHG
Greenhouse gas
HHV
Higher heating value
HOP
Hours of operation
HR
Heat rate
hr
Hour
kJ
Kilojoule
kWh
Kilowatt-hour
Ib/MMBtu
Pounds of a pollutant per million British thermal units
LFG
Landfill gas
Mg
Megagram or metric ton
min
Minute
MW
Molecular weight
NMOC
Nonmethane organic compounds
NSPS
New Source Performance Standard
PM-10
Particulate matter less than 10 micrometers in diameter
ppmv
Parts per million by volume
RIC
Reciprocating internal combustion
RS"
Reduced sulfur
SCR
Selective Catalytic Reduction
SD
System down-time
yr
Year
SYMBOLS
CH4 Methane
CO Carbon monoxide
C02 Carbon dioxide
r|CO| Collection efficiency of the LFG collection system (% collected/100%)
r)cmb Combustion efficiency of the LFG control/utilization device [(inlet - outlet)/inlet]
Cc02 Concentration of C02 (ppmv)
Hcm Heat content of methane
H2S Hydrogen sulfide
k LFG generation constant (yr~1)
LFfr Fraction of the landfill area to be controlled (% controlled/100%)
Lq CH4 generatbn capacity of a landfill (ft3/Mg)
N2 Nitrogen
NOx Nitrogen oxides
Qj Heat input (MMBtu/hr)
qt LFG fuel flow rate (fr/min)
S02 Sulfur dioxide
V|_fG Generation rate of LFG (ft3/unit time)
FRCH4 CH4 content of LFG (ft3CH4/ft3 LFG)
vi
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CONVERSIONS
Multiply
By
To Obtain
LENGTH
Feet
Inches
Meters
Meters
Meters
AREA
Acres
Hectares
Square meters
Square feet
VOLUME
Acre feet
Barrels
Cubic feet
Cubic meters
Gallons
MASS
Kilograms
Pounds
Tons (english)
Tonnes (metric)
Tonnes (metric)
DENSITY
Kilograms per cubic meter
Pounds per cubic foot
Grams per liter
PRESSURE
Pascal
Atmospheres
Pounds per square inch
Pascals
Bar
Inches of water
0.3048
0.0254
39.37
3.281
,6
10'
4.4050
2.471
10.764
0.0929
123.35
0.159
0.0283
1,000
3.785
2.2046
0.4536
0.907
1.1023
1,000
0.0624
16.01
0.0624
1
101,325
6,894
1.45 X 10"'
10s
249
Meters
Meters
Inches
Feet
Microns
Square meters
Acres
Square feet
Square meters
Cubic meters
Cubic meters
Cubic meters
Liters
Liters
Pounds
Kilograms
Tonnes (metric)
Tons (english)
Kilograms
Pounds per cubic foot
Kilograms per cubic meter
Pounds per cubic foot
Newton/m2 (1 Newton is the force required
to accelerate 1 kg at 1 m/second2.)
Pascals
Pascals
Pounds per square inch
Pascal
Pascal
(Continued)
vii
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CONVERSIONS (Continued)
Multiply
By
To Obtain
POWER
Watts
1
Newtonmeter/sec. or Joule/sec.
Watts
0.05692
Btu/minute
Watts
1.341 x 10"3
Horsepower
ENERGY
Joules
1
Wattsecond or Newtonmeter
Kilowatt-hours
3,415
Btus
Kilowatt-hours
1.341
Horsepower-hours
Kilowatt-hours
3.60 X 106
Btu
Btus
1,054
Joules
MISCELLANEOUS
Cubic meters per hectare
14.291
Cubic feet per acre
Cubic meters per hour
0.5886
Cubic feet per minute
Cubic feet per minute
0.02831
Cubic meters per minute
Cubic feet per lb per year
61
Cubic meters per tonne per year
Btu/scf
37,243
Joule/cubic meter
viii
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1. INTRODUCTION
t .1 Background
The United States Environmental Protection Agency (EPA) proposed emission guidelines for existing
municipal solid waste landfills (hereafter referred to as municipal landfills) and New Source Performance
Standards (NSPS) for new municipal landfills in May of 1991. The guidelines and NSPS are expected to
require from 500 and 700 landfills to install and maintain landfill gas (LFG) collection and control systems.1
The LFG collection and control systems are required to reduce LFG emissions that include nonmethane
organic compounds (NMOC). Control or utilization of LFG emissions is also desirable to reduce emissions
of greenhouse gases (GHGs), such as methane.
In this document, LFG control systems refer to flares, where there is no recovery of the associated energy.
In contrast, LFG utilization refers to the recovery of LFG energy either as primary heat (e.g., industrial boiler
or space heater) or as a fuel source to drive electricity generating equipment. Currently, these are the most
common utilization options. Additional LFG utilizatbn projects include the upgrading of LFG for use as
pipeline quality gas or vehicle fuel. Potential future uses of LFG include its use in fuel cells or as a
feedstock in chemical manufacturing processes. The Air and Energy Engineering Research Laboratory
(AEERL) of EPA is conducting ongoing research to provide information on energy conversion and other
utilization optbns for LFG as a means of assisting landfill owners/operators that may be affected by the
new municipal landfill emission requirements.
The combustion of LFG in flares, reciprocating internal combustion (RIC) engines, gas turbines, and boilers
produces emissions of nitrogen oxides (NOx) and carbon monoxide (CO), often referred to as secondary
emissbns. Since some of these secondary emissions are of concern in ozone, CO (and in some cases
particulate matter less than 10 microns [PM-10]) nonattainment areas, methods to comparatively assess
emissbns resulting from LFG control/utilizatbn with other forms of energy production are needed. Also,
GHGs are of global concern and, therefore, a comparison of the net benefits or drawbacks associated with
LFG control/utilization and other forms of energy production is often of interest.
Until recently, comparative informatbn on the relative types and amounts of primary emissions resulting
from uncontrolled municipal landfills and secondary emissbns produced by the systems used to
control/utilize LFG were lacking. During EPA's development of the NSPS for municipal landfills and work
on developing AP-42 emissbn factors for municipal landfills, emissbn test data were obtained that can be
used to assess both uncontrolled LFG emissions and emissions associated with various LFG
control/utilization projects.2,3 EPA AEERL continues to gather informatbn on the emissions from LFG
utilization/control and this information will be used to make future refinements to the data bases used to
quantify and compare air pollutant emissions associated with these projects.
1.2 Purpose
The primary puipose of this document is to provide a methodology to prepare emission factors for criteria
air pollutants and GHGs resulting from LFG control/utilizatbn projects. This informatbn may be useful to
State/Regional officials, owners and operators of landfills, and LFG developers during evaluations of
available landfill gas control/utilization technologies. The emissions estimatfon methodology is based on
the principles of mass balance and also relies on assumptions of primary pollutant (e.g., NMOC) control
efficiencies and secondary pollutant production rates as measured during source tests conducted over
approximately the last 10 years. Examples using case studies are provided to illustrate the steps in the
methodology. In these cases, sources of information on default concentrations for LFG constituents and
secondary pollutant emissbn rates are given, but the reader is cautioned that site-specific information
should be used if available.
1
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in addition, it is the purpose of this document to acquaint the reader with sources of information and
methods to quantify and compare emissions from alternative energy sources and compare them to
emissions from LFG utilization technologies. Emissions are quantified in units that allow for direct
comparisons between LFG utilization options (e.g., LFG RIC engine versus LFG turbine) and alternative
energy sources (e.g., LFG utilization option versus coal-fired boiler power plant).
The secondary purpose of the document is to provide additional data and methods to prepare both
uncontrolled and controlled LFG emission inventories. Using these methods, an analyst can prepare an
air pollution balance sheet of uncontrolled landfill versus controlled landfill emissions.
A methodology for the preparation of a complete balance sheet of all air pollutant emissions associated with
the procurement, refinement, transport, storage, and use of LFG and comparison fuels (e.g., coal) is
beyond the scope of this document. However, in comparing emissions on large spatial scales (e.g.,
national, global), emissions resulting from each stage of the fuel cycle may be significant. The reader is,
therefore, cautioned that the methodology and guidance presented here does not account for all emissions
in the fuel cycle.
The use of the methodology presented in this document is expected to vary depending on the location of
the landfill being evaluated. Examples of where the methodology may be useful include:
analyzing ozone precursor emission increases and decreases (e.g., NMOC, NOx) in
nonattainment areas;
assessing impacts of potential emission increases and decreases of GHGs;
accounting for the energy benefits of utilizing LFG as compared to LFG control (i.e.,
flaring); and/or
comparing emissions from controlled and uncontrolled landfills.
2
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2. ASSESSING UNCONTROLLED LFG EMISSIONS
This chapter presents a methodology for estimating uncontrolled NMOC and GHG emissions from landfills.
The best estimates for uncontrolled emissions will be made with the use of site-specific data such as LFG
generation rate; collection efficiency; and methane (CH4), carbon dioxide (C02), and NMOC content.
Alternatively, the LFG generation rate and emissions of uncontrolled substances can be modeled with
EPA's Landfill Air Emissions Estimation Model {EPA's model).4 A new version of EPA's model is expected
to be released by December 1994. For instances where site-specific data are not available, default values
are provided in the model.
For uncontrolled landfills, NMOC is of concern due to its role as an ozone precursor. Previous efforts by
EPA to estimate the NMOC content of LFG provide a range of values from a few hundred parts per million
by volume (ppmv) as hexane to over 10,000 ppmv as hexane.3 A mean value of 1,170 ppmv as hexane
was reported in the AP-42 background document and a recommended value of 4,400 ppmv was given for
landfills known to have a co-disposal history (i.e., landfills that received both municipal and
commercial/industrial organic wastes). The AP-42 section on landfill emissions may be revised within the
next 1 to 2 years to incorporate new emissbn test data results. With the incorporation of new source test
data, the default values for LFG constituents are expected to change. The background given here is
provided to further stress the importance of the use of site-specific data.
EPA's model can be used to estimate seasonal or annual uncontrolled landfill emissions. However, if site
specific data are available for the LFG generation rate and characterization (i.e., concentrations of CH4,
C02, and NMOC), better estimations of seasonal or annual emissions can be made with the following
equation:
ERUC, = [Cc] [MW/(385.1 x 106)] [VLFG] [1/2,000] (eq. 1)
Where: ERucl = uncontrolled emission rate (ton/yr)
Cc = concentration of the compound of interest (ppmv)
MW = molecular weight of C (Ib/Ib-mole)
385.1 x 106 = conversion factor, ppmv to lb/ft3
VLFG - generation rate of LFG (ft3/yr)
1/2,000 = conversion factor, lb to ton
An example use of equation 1 to develop an uncontrolled emission inventory is provided Section 4.1.
3
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3. DETERMINING CONTROLLED LFG EMISSION FACTORS AND EMISSION RATES
This chapter presents the methodology and supporting data needed to estimate emissions from LFG control
and utilization equipment. Sections 3.1 through 3.3 cover emissions of criteria pollutants or ozone
precursors, including CO, NOx, NMOC, and sulfur dioxide (S02). Sections 3.4 and 3.5 provide a discussion
on the estimation of GHG emissions (i.e., CH4 and C02).
To allow for comparison of LFG emission factors (EFs) to other energy sources (e.g., coal, distillate oil,
natural gas) and to make comparisons between the various utilization options at a given landfill, controlled
EFs are expressed as follows:
Flares and Boilers EFs are expressed as a function of the heat input to the system (i.e., heat content
of the LFG). An example would be pounds of a pollutant per million British thermal units (Ib/MMBtu).
Comparisons can be made to other utilization options or energy sources using this EF and those from
other published sources (e.g., AP-42).
RIC Engines and Turbines EFs are also derived in terms of heat input. However, since the work
performed by these utilization options has primarily been in the form of electricity generation, EFs are
then converted to terms of energy production [e.g. pounds per kilowatt-hour (Ib/kWh)]. These EFs are
derived from the mass per heat input EFs with the use of a plant heat rate (HR). The value of HR
(Btu/kWh) accounts for the thermal efficiency of the combustion unit, the efficiency of the generator, and
parasitic energy losses of the system (power used to run auxiliary equipment).
A comparison can be made to uncontrolled emissions (determined in Section 2) by calculating seasonal
or annual emission totals from the EFs determined for control/utilization equipment. For these comparisons,
the efficiency of the LFG collection system (ti^) needs to be established. Although collection efficiencies
have been reported to range from 60 to 85 percent, a default of 75 percent is often used when site-specific
data are not available.3 As with all of the data presented in this document, site-specific data should be
used whenever possible to ensure the accuracy of emission estimates. Values of used in the
methodology presented in this document are corrected to account for the fraction of the landfill to be
controlled (LFfr). For instance, if 90 percent of a landfill is to be served by a collection system, a 75 percent
system efficiency, t^, is estimated as 67.5 percent [i.e., (0.75 x 0.90) x 100],
To determine the EFs described above, the heat input (Qj) to the control/utilization device must first be
estimated. The LFG flow rate (qf) can be estimated by multiplying the LFG generation rate by the collection
efficiency. It is assumed that ambient air infiltration is kept to a minimum (< 5 percent) and that this will
have a negligible impact on the LFG composition (e.g., CH4 and C02 content). Ambient air infiltration
refers to ambient air (i.e., occurring above the landfill) being drawn into the landfill and hence present in
the LFG due to overdrawing of the collection system. Table 1 lists the default values for determining
controlled emission rates, if site-specific data are not available. Q( can then be calculated as follows:
Qj = [q,l [FRCH4] lHcJ E1/106] [60]
(eq. 2)
Where: Q,
heat input (MMBtu/hr)
LFG fuel flow rate (ft3/min) = [LFG generation rate] [r^]
LFG collection efficiency of the system [% collected/100%] [LFfr]
fraction of the landfill to be controlled (% controlled/100%)
LFG CH4 content (ft3 CH4/ft3 LFG)
heat content of methane (1,012 Btu/ft3)
qf
led
4
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1/1 o6
60
TABLE 1. DEFAULT LANDFILL PARAMETERS
Parameter Value
(percent)
CH4 content of LFG* 50
C02 content of LFG* 50
LFG collection efficiency (tiC0|)* 75
System down-time (SD)a
- flare control 3
- LFG utilization (engine, boiler, or turbine) 7
* Reference 3.
The LFG generation rate needed for equation 2 can be determined by running EPA's model and summing
the generation rates for CH4 and C02. System down-time (SD) refers to the amount of time on an annual
basis that the control/utilization system is not operated due to maintenance or break-downs. Estimates of
SD should be obtained from equipment vendor guarantees. The values for SD in table 1 were obtained
from an industry contact and represent values that may be quoted by an equipment vendor.Ū The following
Sections describe the methodology for developing EFs and seasonal or annual emission estimates.
3.1 Carbon Monoxide and Nitrogen Oxides
Emission factors for the secondary compounds, CO and NOx, are presented in table 2. Except for RIC
engines, these EFs were developed from a statistical analysis of recent source test data.5"16 The CO and
NOx EFs for RIC engines were developed from data published in EPA's NSPS Background Document.3
All EFs are presented in table 2 in terms of the heat input to the control or utilization device. For electricity
generating utilization equipment, the method for converting EFs to units of mass of CO or NOx emitted per
unit of energy output is presented in the RIC subsection below.
Flares. The EFs for flares have the highest data quality ratings in table 2, due to the relatively large
number of high quality source tests available for use in their development. The "B" rating does not
necessarily mean that the EFs are of the highest possible quality, since quality ratings are assigned from
A (highest) through E (lowest). In general, "A" rated EFs are developed from the best source test data
available and there is a minimal amount of variability in the data that represents a randomly selected
sample of the source population. At the other end of the scale, an "E" rated EF may be developed from
lower quality test data and/or there may be evidence of variability within the source population. Also, the
"E" rated EF may not have been derived from a large randomly-selected sample of the source population.17
Personal communication, C, Anderson, Rust Environment and Infrastructure, Naperville, IL, August 8,1994.
5
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TABLE 2. DEFAULT LFG EMISSION FACTORS FOR CO AND NOx
Control or
Utilization
Device
Emission Factor
CO
X
o
z
Ret.
kg/kJ
Ib/MMBtu
Data
Quality"
kg/kJ
Ib/MMBtu
Data
Quality"
Enclosed Flares*
7.22 x 10"8
0.168
B
3.92 X 10"8
9.12 X 10"2
C
5-11
RIC Engines (lean
burn)
1.99 x 10"7
0.462
D
1.03 x 10"7
0.239
D
2
RIC Engines (rich
burn)
3.37 x 10"7
0.783
N/A
3.80 x 10"7
0.883
N/A
2
Gas Turbines
4.10 x 10~8
9.54 x 10~2
E
4.07 x 10"8
9.49 x 10"2
E
12-15
Boilers/
Steam Turbines^
2.37 x 10"9
5.52 x 10"3
D
1.23 x 10"8
2.85 x 10"2
E
5,16
NOx is expressed as N02.
Data quality ratings are from A (highest) to E (lowest).
* Data are for enclosed flares. No data on open flares were available.
EFs may require adjustment upward by up to 12 percent to account for equipment heat loss with the use of
LFG versus comparison fuels.
To calculate seasonal or annual emissions using the EFs in table 2, the heat input rate to the
control/utilization device (from equation 2) is used along with an estimate of the system down-time as
follows (adjustments may be needed when evaluating emissions for boilers or steam turbines, see below):
Annual emissions (ton/yr) = [EF] [Q|] [HOP] [1/2,000] (eq. 3)
Where: EF = emission factor (Ib/MMBtu)
Qj = heat input (MMBtu/hr, from eq. 2)
HOP = hours of operation (hr/yr) = 8,760 [1 - (SD/100 %)]
SD = system down-time (%)
1/2,000 = conversion factor, lb to ton
Boilers and Steam Turbines. Emission factors for boilers and steam turbines using LFG are also
presented in table 2. An EF based on two source tests for boilers is also listed for steam turbines due to
the similarity of these two sources and the lack of any quality source test data for steam turbines. Annual
emissions can be calculated using the EFs above and equation 3.
To obtain an EF or an emissions estimate for use in comparison to other energy options (e.g., natural gas-
fired industrial boiler), the EF or the emissions estimate should be adjusted upward by 12 percent. This
adjustment is needed to account for the approximate 12 percent loss in heat output associated with the use
of LFG versus a conventional fuel (e.g., natural gas).1Ū Therefore, the EF in table 2 or the result from
equation 3 should be adjusted by dividing by 0.88 (1 - 0.12). An example scenario is given in Section 4.4
6
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that shows adjusted boiler EFs and emission rates.
If a flare back-up control is to be used during system down-time (i.e., for utilization options), equation 3
should be applied again using the number of hours that the flare will be operated [e.g., HOP = (8760) x
(SD/100 percent)! and the appropriate EF for a flare. The emissions from the flare are then added to the
emissions for the utilization option to obtain an annual total. Examples of the estimation methodologies
are included in Chapter 4.
For steam turbines, methods for converting the EF to terms of energy output are given in the next
subsection.
RIC Engines and Gas Turbines. Table 2 also provides EFs for CO and NOx from RIC engines and gas
turbines using LFG. Emission factors obtained from table 2 above do not account for emission reductions
associated with the use of control equipment such as CO catalysts in RIC engines. One test report for RIC
engines indicated that a CO conversion efficiency of approximately 74 percent (range of 58-88 percent) is
achievable with the use of a CO catalyst. Caution should be used in assigning control efficiencies for any
catalyst, since poisoning of the catalyst (e.g., with silicon-based compounds) may be a problem.19 If a
catalyst is present, the controlled emission factor can be calculated as follows:
Controlled EF = [EF] [1 - ricat] (eq. 4)
Where: Tical = control efficiency of the catalyst (% conversion/100%)
Currently, controls for CO and NOx on LFG utilization equipment are not widely used and sufficient data
are not currently available to determine default values for the use of such controls. Therefore, equation
5 is provided for specific instances, such as when a guaranteed conversion efficiency is obtained from an
equipment vendor.
As with flares and boilers, seasonal or annual emission totals can be calculated with the EFs presented
above, the heat input to the system, and equation 3. As discussed above for boilers and steam turbines,
emissions from a backup flare should also be considered in annual or seasonal totals.
Since the utilization equipment in table 2 are primarily used to generate electricity, it is desirable to express
EFs in terms of mass per unit of energy output. This conversion allows for comparisons of potential
emissions to be made to other types of energy utilization (e.g., coal or natural gas combustion). To obtain
these factors, the EFs in table 2 are multiplied by HR, a value that represents the overall facility operating
efficiency:
EF (Ib/kWh) = [EF (Ib/MMBtu)] [HR] [1/106] (eq. 5)
Where: HR = facility heat rate (Btu/kWh)
The facility heat rate accounts for the efficiency of the combustion unit and generator and any parasitic
energy losses (i.e., from running auxiliary equipment). Table 3 provides a list of HR default values for RIC
engines and gas and steam turbines. These values are averages that were obtained from source test
reports and equipment vendors with the exception of steam turbines. Steam turbines are assumed to have
an overall plant efficiency of 30 percent.20 This equates to a facility heat rate of 11,373 Btu/kWh. As
mentioned earlier, site-specific data are preferable to the use of default values presented in this document.
Values of HR, for example, may vary considerably for a given technology depending on the size of the unit.
7
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TABLE 3. DEFAULT FACILITY HEAT RATES FOR LFG UTILIZATION
Utilization Device
Heat Rate
Reference
Number
kJ/kWh
Btu/kWh
RIC engine
10,458
9,906
2lb,c
Gas turbine
15,042
14,247
18, 22d
Steam turbine
12,009
11,373
20
3.2 Nonmethane Organic Compounds
Controlled NMOC EFs can be derived by using equation 6 below. The calculation requires values for the
NMOC and CH4 concentrations in LFG and the combustion efficiency (r|cmb) of the particular
control/utilization device. The best estimates of ncmb will be equipment vendor guarantees. In order to
make approximate estimates of NMOC emissions, a default value of 98 percent can be assumed for ticmb
for all control/utilization options. Well maintained and operated equipment should achieve in excess of 98
percent combustion. However, data reviewed from source tests of different control/utilization options
indicate that these levels are not always achieved in practice. Sufficient data is not currently available to
develop a default value of -qcmb for each control/utilization option. Therefore, the importance of using
vendor-guaranteed efficiencies cannot be over emphasized.
An NMOC EF for collected LFG (NMOC EFco() can be derived as follows:
EFgQ, (Ib/MMBtu) = [CNMOC] [MW/(385.1 x 106)] [FRCH4]"1 [Hcj' [1061 [1 - ricmb] (eq. 6)
Where: CNMOG = NMOC concentration of LFG (ppmv as hexane)
MW
molecular weight of NMOC as hexane (86 lb/lb-mo!e)
385.1 x 106
conversion factor, ppmv to lb/ft3
Ff'cH4 =
LFG methane content (ft3 CH4/ft3 LFG)
II
heat content of methane (1,012 Btu/ft3)
106
conversion factor, Btu to MMBtu
^Icmb
combustion efficiency of the equipment (% combusted/100%)
The EF from equation 6 can be converted from a heat input to a power output basis with equation 5 and
the appropriate value of HR from table 3.
The method used to estimate seasonal or annual NMOC emissions needs to account for the following
sources of emissions: (1) emissions that occur while LFG is being collected, but not combusted due to the
inefficiency of the combustion device; (2) emissions occurring during system operation due to inefficiencies
of the collection system (i.e., NMOC as part of uncollected LFG); and (3) emissions occurring during system
b Personal communication, Eldon Rumba, Waukesha Pearce, Houston, TX, July 7,1994.
c Personal communication, Dean Manning, Cooper Energy Services, Garden Grove, CA, July 7, 1994.
d Personal communication, Ron Swift, Solar Turbines, San Diego, CA, July 7, 1994.
8
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down-time (SD). Equation 7 below accounts for all of these sources to estimate controlled NMOC
emissions (the final term, 11^, refers to the combustion efficiency of any backup control, such as a flare):
Annual emissbns (ton/yr) = {[NMOC EF^] [Qj] [HOP] [1/2,000]} +
{[NMOC ERucI] [1 - ncol]} + {{NMOC ERuc|] [ncol] [SD] [1 - iicmb]} (eq. 7)
Where: NMOC EF^ = controlled EF for collected LFG, see eq. 7 (Ib/MMBtu)
Qj = heat input to the system, see eq. 3 (MMBtu/hr)
NMOC ERucl = uncontrolled NMOC emission rate, see Section 2 (ton/yr)
r|CO| = efficiency of LFG collection system (% collected/100%)
HOP = hours of operation (hr/yr) = 8760 [1 - (SD/100%)]
SD = fraction of time the system is down (% down)
r|cmb = combustion efficiency of the flare backup, if applicable
(% combusted/100%)
1/2,000 = conversion factor, lb to ton
3.3 Sulfur Dioxide
Emissions of S02 are determined using mass balance techniques. The primary assumption used to
estimate emissions is that 100 percent of the reduced sulfur (RS") compounds in the LFG are oxidized to
S02 for any control or utilization device evaluated.
Ideally, the results of an analysis of the LFG for total sulfur (expressed as ppmv S) should be used to
determine an EF and to estimate seasonal or annual emissbns. The first step is to determine the amount
of S02 produced from the combustion of all sulfur-containing compounds. This is performed using two
substeps. The first of these is to convert the concentration of S in ppmv to a mass/volume relationship:
mass/volume (lb/ft3) = [Cs] [MWg/385.1 x 106] (eq. 8)
Where: Cs = LFG concentration of S (ppmv)
MWS = molecular weight of S (32 Ib/lb-mole)
385.1 x 106 = conversion factor, ppmv to lb/ft3
The second substep is to convert the mass of S per unit volume of LFG to an EF in terms of mass of S02
produced per unit of heat input:
EFS02 = [lb S/ft3 LFG] [FRCH4]"1 [HeJ1 [MWs02/MWs] [mole SO^mole S] [106] (eq. 9)
Where: EFS02
lb SOg/MMBtu
FRCH4
LFG CH4 content (ft3 CH4/ft3 LFG)
heat content of methane (1,012 Btu/ft3)
mwS02
molecular weight of S02 (64 Ib/lb-mole)
MWg
molecular weight of the S (32 Ib/lb-mole)
mole S02/mole S =
mole S02 produced per mole S consumed (Ib-mole/ib-mole)
9
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Commonly, LFG analyses are available for individual RS" compounds and not total S. Therefore, S02
production is determined in a similar fashion using equations 8 and 9 for each RS" compound. The
appropriate values for concentration and MW for each species will be needed to determine species-specific
S02 production potentials. After determining S02 production for each RS" compound, these values are
summed to provide a total S02 EF:
Total S02 EF (Ib/MMBtu) = E EFS02 (1.i} (eq. 10)
Where: EFS02 ^ = first EFS02 determined (Ib/MMBtu)
EFS02 ^ = last EFS02 determined (Ib/MMBtu)
Seasonal or annual emissions can be determined using equation 3. Emission factors can be converted
to terms of mass per unit of energy output with equation 5.
3.4 Methane
Emissions of CH4 are estimated using the same methods established for NMOC (see Section 3.2). As with
NMOC, sufficient data are not currently available to develop a methane control efficiency for each
control/utilization option. However, well operated and maintained equipment should achieve in excess of
99.9 percent control (i.e., r(cmb > 0.999). This value can be used as a default when vendor-guaranteed
combustbn efficiencies are not available. Additional variables needed to use equations 6 and 7 include
LFG CH4 concentration and the molecular weight of CH4 (MW = 16). As with NMOC, an EF in terms of
power output can be derived using equation 5 and the appropriate plant heat rate given in table 3.
3.5 Carbon Dioxide
Emissions of C02 are also determined by mass balance. Carbon dioxide emissions are the result of C02
being a significant component of LFG as well as being formed during the combustion of CH4 and NMOC.
The first step is to express the amount of LFG C02 (i.e., the C02 fraction of the collected LFG) flowing
through the control device in terms of mass per heat input. Using equation 6:
Step 1:
C02 EF1 (Ib/MMBtu) = [Cc02] [MW/385.1 x 106] [FRCH4]"1 [Hcj' [106] [1 -ncmb]
Where: CC02 = C02 concentration of LFG (ppmv)
MW = molecular weight of C02 (44 Ib/lb-mole)
385.1 x 106 = conversbn factor, ppmv to lb/ft3
FRCH4 = LFG CH4 content (ft3 CH4/ft3 LFG)
Hcm - heat content of methane (1,012 Btu/ft3)
106 = conversbn factor, Btu to MMBtu
Ticmb = combustion efficiency of the device (r)cmb = 0 for C02)
The next step is to determine the amount of C02 formed from the combustbn of CH4 and to express it in
terms of heat input. First, the LFG CH4 concentration is converted to a mass per heat input relatbnship
through modification of equation 7 by substituting the following variables for methane: CCH4, MW =16, and
the control efficiency (default ricrnb = 0.999).
Step 2.1:
lb CH4/MMBtu = [CCH4] [MW/(385.1 x 106)] [FRCH4]"1 \Hcj" [106] [i1cmb] (eq. 11)
10
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Next, the methane input to the system is converted to C02 output:
Step 2.2:
C02 EF2 (Ib/MMBtu) = [lb CH4/MMBtu] [MWCQ2/MWCH4] [mole CH4/mo!e C02] (eq. 12)
The third step is to determine C02 formation from the combustion of NMOC. Equations 11 and 12 can be
used by substituting the NMOC concentration, molecular weight, and combustion efficiency (NOTE: 6 moles
of C02 are formed for each mole of NMOC as hexane combusted):
Step 3.1:
lb NMOC/MMBtu = [CNMOC] [MW/(385.1 x 106)] [FRCH4]~1 [HeJ"1 [106] focmb]
Step 3.2:
C02 EF3 (Ib/MMBtu) = [lb NMOC/MMBtu] [T|cmb] [MWc02/MWnmoc] [6 mole CO^mole NMOC]
Finally, the amount of CO formed during the combustion of organics in steps 2 and 3 above needs to be
subtracted out. For this step, the vendor-supplied CO emission factor (or the default CO EF) from table 2,
if necessary) is used and converted to the C02 equivalent:
Step 4:
C02 EF4 (Ib/MMBtu) = [EFco] [MWC02/MWC0] (eq. 13)
The final step is to combine the results of the four previous steps to obtain an overall EF for collected LFG
(C02 EFC0|):
Step 5:
C02 EFcd (Ib/MMBtu) = EF1 + EF2 + EF3 - EF4 (eq. 14)
The EF determined by equation 14 can be used to make comparisons to other power generation processes
by converting it to Ib/kWh (using equation 5). This EF does not account for C02 emissions that are not
captured by the LFG collection system. However, as discussed in Section 1, the intent of this document
is to provide both methods to derive EFs for alternative energy comparisons and methods to prepare
uncontrolled and controlled emission estimates. Comparison EFs (e.g., Ib/MMBtu or Ih/kWh) do not include
emissbns of uncollected LFG constituents. Hence, when preparing controlled emission inventories
equation 7 should be used to estimate C02 emissions, including uncollected C02, as follows:
Annual emissions (ton/yr) = {[C02 EFcd] [Qj] [HOP] [1/2,000]} +
{[C02 EFU [1 - t^,]} + {[C02 ERJ [ t^,] [SD] [1 - T,OTb]}
Where: C02 EF^ = controlled EF for collected LFG, see eq. 15 (Ib/MMBtu)
Qj = heat input to the system, see eq. 3 (MMBtu/hr)
C02 ERucj = uncontrolled C02 emission rate (ton/yr)
t)coj = efficiency of LFG collection system (% collected/100%)
HOP = hours of operation (hr/yr) = 8760 [1 - (SD/100%)]
SD = system down-time (% down)
ncrT)b = combustion efficiency of flare backup, if applicable, (Hcmb - 0 for C02)
11
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4. EXAMPLE ASSESSMENT OF LFG CONTROL AND UTILIZATION
An example assessment is presented in this chapter to illustrate the methods presented in Chapters 2
and 3. The example includes the development of an uncontrolled landfill emissions inventory and the
development of EFs and controlled emission estimates following LFG control/utilization with the following
technologies: a flare, an RIC engine, a gas turbine, and a boiler. Comparisons are made for the two
electricity-generating utilization options to electricity production at a coal-fired steam power plant and a
natural gas turbine power plant. Emissions from the LFG boiler are compared against an industrial boiler
of similar size fired on natural gas or distillate oil.
4.1 Uncontrolled Landfill Emissions
Table 4 provides operating parameters for the example landfill. These landfill values were taken from a
case study for a landfill operating near the coast of California. The LFG collection efficiency for this system
guaranteed by the vendor is 75 percent, however only 90 percent of the landfill will be served by the
collection system. Therefore, will be 0.75 x 0.90 = 0.675. The modeled LFG generation rate is 1,160
ft3/min. Therefore, the estimated collection rate of LFG is 67.5 percent of 1,160 fr/min or 783 ft3/min. A
hypothetical sampling program conducted on the LFG established the LFG constituent concentrations given
in table 5.
TABLE 4. EXAMPLE LANDFILL OPERATING PARAMETERS
Date Opened: 1966
Waste in Place: 4 million tons
Waste Fill Rate: 850 tons/day
Total Fill Area: 490 acres
Area Filled (early 1991): 90 acres
Climate: Mediterranean
Annual Rainfall: 11 inches
Fraction of the Landfill to be Controlled = 0.90
LFG Collection System Efficiency = 75%
LFG Collection Rate: 783 fr/min
LFG Generation Rate: 1,160 ft3/min
Uncontrolled emissions are estimated with the representative values from table 5 and equation 1.
For example, annual uncontrolled NMOC emissions are calculated as follows:
NMOC ERUC| (ton/yr) = [CJ [MW/(385.1 x 106)] [VLFG] {1/2,000]
[1,170 ppmv] [86/(385.1 x 106)] [6.10 x 108 ft3/yr] [1/2,000]
= 79.7 tons/yr
Annual uncontrolled emissions for NMOC, C02, and CH4 are summarized below in table 6.
12
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TABLE 5. LFG CONSTITUENT CONCENTRATIONS
Compound
Molecular Weight
Concentration: (ppmv)
Ozone Precursors*
NMOC as hexane
Reduced Sulfur Compounds
t-Butyl mercaptan
Dimethyl disulfide
Carbon disulfide
Carbonyl sulfide
Dimethyl disulfide
Dimethyl sulfide
Ethyl mercaptan (ethanethiol)
Hydrogen sulfide
Isopropyl mercaptan
Methyl ethyl sulfide
Methyl mercaptan (methanethiol)
Greenhouse Gases*
Carbon dioxide
Methane
86
90
92
76
60
92
62
62
34
76
76
48
44
16
1170
0.14
0.14
0.11
0.095
0.14
6.50
0.42
43.6
1.00
0.29
2.20
450.000
550,000
* This is equivalent to the default concentration given in AP-42.3
t NMOC is also a member of this group.
TABLE 6. EXAMPLE ASSESSMENT: ANNUAL UNCONTROLLED EMISSIONS
Compound
Annual Emissions, ERucj
(Mg/yr)
(ton/yr)
Ozone Precursors
NMOC as hexane
Greenhouse Gases
Carbon Dioxide
Methane
72.3
14,223
6,321
79.7
15,682
6,970
13
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4.2 Controlled Landfill Gas Emissions
As discussed in Section 3, the first step to deriving EFs and seasonal or annual emissions for each LFG
control or utilization device is to estimate the heat input (Qj) to the control or utilization system. Using
equation 2:
Qi
[qf] [FRCH4] [HcJ I1/106) [60]
[783 f^LFG/min] [0.55 ft3 CH4/ft3 LFG] [1,012 Btu/ft3 CH4] [1 /106] [60]
26.15 MMBtu/hr
The derivation of EFs and emission estimates following flare control or LFG utilization using a RIC engine,
gas turbine, or boiler is presented in the following Sections.
4.2.1 Emissions Resulting from LFG Control Using a Flare
Secondary Compounds. Emissions of secondary compounds, such as NOx and CO, are calculated using
the EFs presented in table 2 and equation 3. For example, CO emissions from the flare would be:
Annual emissions (ton/yr)
[EF] [Qj] [HOP] [1/2,000]
[0.168 Ib/MMBtu] [26.15 MMBtu/hr] [8,760 {1 - (3/100)} hr/yr] [1/2,000]
18.7 ton/yr
The annual hours of operation (HOP) are estimated with the default system down-time for flares of
three percent from table 1. A summary of EFs and annual emission estimates for secondary compounds
is given in table 7.
Controlled Primary Emissions (NMOC and CH4). NMOC emissions are determined by first deriving an
EF in terms of heat input to the flare. Using the NMOC concentration from table 5, an assumed
combustion efficiency of 98 percent, and equation 6:
NMOC EFcol (Ib/MMBtu)
I^NMOcl
[MW/(385.1 x 106)] [FRCH4]~1 [HcJ-' [106] [1
[1,170 ppmv] [86/385.1 x 106] [ft3 LFG/0.55 ft3 CH4] [ft3 CH4/1,012 Btu] [106] [1 - (98/100)]
9.39 x 10"3 Ib/MMBtu
Annual emissions are then calculated with equation 7 and a collection efficiency of 67.5 percent. It is
assumed that there is no backup control device for the flare during system down-time Cncmb = 0), also HOP
was determined assuming SD - 3 percent:
Annual emissions (ton/yr)
{[NMOC EF^,] [Qj][HOP] [1/2,000]} + {[NMOC ERuc|][1 - r,co|]} +
{NMOC ER^hJISD] [1 -ncmb]}
{[9.39 x 10"3 Ib/MMBtu] [26.15 MMBtu/hr] [8,497 hr/yr] [1 ton/2,000 lb]} +
{[79.7 ton/yr] [1 - 0.675]} + {[79.7 ton/yr] [0.675] [0.03] [1 - 0]}
= 1.04 ton/yr + 25.9 ton/yr + 1.60 ton/yr
28.5 ton/yr
14
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TABLE 7. FLARE EXAMPLE: SUMMARY OF CONTROLLED AIR POLLUTANT
EMISSION FACTORS AND EMISSION RATES
Compound
Emission Factor, EF^,
Emission Rate
kg/kJ
Ib/MMBtu
Mg/yr
ton/yr
Criteria Pollutants/Ozone Precursors
Carbon Monoxide
7.22 x 10"8
0.168
16.9
18.7
Nitrogen Oxides (as N02)
3.92 x 10"8
9.12 x 10"2
9.2
10.1
NMOC (as hexane), total
25.9
28.5
from LFG combustion
4.04 x 10"9
9.39 x 10"3
0.94
1.04
during System Downtime
1.46
1.60
from uncollected LFG
23.5
25.9
Sulfur Dioxide
7.01 x 10"9
1.63 x 10~2
1.64
1.81
Greenhouse Gases
Carbon dioxide, total
25,792
28,412
from LFG combustion
8.87 x 10"5
207
20,863
22,997
during System Downtime
289
318
from uncollected LFG
4,627
5,097
Methane, total
2,188
2,411
from LFG combustion
1.77 X 10~8
4.11 X 10"2
4.15
4.57
during System Downtime
128
141
from uncollected LFG
2,056
2,265
The CH4 EF and emissions are determined using the same methods used to calculate the NMOC EF and
emissions with the exception of an assumed combustion efficiency of 99.9 percent. Using the CH4
concentration from table 5, the CH4 combustion efficiency, and equation 6:
CH4 EFco| (Ib/MMBtu)
ICCH4] [MW/(385.1 x 106)] [FRCH4r1 [Hcmf [106] [1 - ncmb]
[550,000 ppmv] [16/385.1 x 106] [ft3 LFG/0.55 ft3 CHJ [ft3 CH4/1,012 Btu] [106] [1 - 0.999]
4.11 x 10"2 Ib/MMBtu
Annual emissions are estimated with equation 7:
Annual emissions (ton/yr)
{[CH4 EFcol][Q,][HOP][1/2,000]} + {[CH4 ERucl][1 - t^,]} + {[CH4 ERuc|] [r^,]] [SD] [1 - Hcmb]}
{[4.11 x 10~2 Ib/MMBtu] [26.15 MMBtu/hr] [8,497 hr/yr] [1 ton/2,000 lb]} +
{[6,970 ton/yr] [1 - 0.675]} + {[6,970 ton/yr] [0.03] [0.675] [1 - 0]}
4.57 + 2,265 + 141
2,411 ton/yr
15
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Controlled EFs and annual emission estimates for NMOC and CH4 are presented in table 7.
Sulfur Dioxide. Emissions of S02 are determined by a mass balance of the amount of sulfur entering the
control system, in the form of RS" compounds, and the amount exiting the system. It is assumed that 100
percent of the RS" is oxidized and that all is emitted in the form of S02. Using the constituent
concentrations from table 5 and equations 8 through 10:
From table 5, RS" compounds, MW, and representative concentrations:
carbon disulfide, 76, 0.11 carbonyl sulfide, 60, 0.095
hydrogen sulfide, 34, 43.6 dimethyl sulfide, 62, 6.5
methyl mercaptan, 48, 2.2 isopropyl mercaptan, 76, 1.0
t-butyl mercaptan, 90, 0.14 ethyl mercaptan, 62, 0.42
dimethyl disulfide, 92, 0.14 methyl ethyl sulfide, 76, 0.29
The first step is to convert the volume to volume concentrations (ppmv) to a mass per unit volume basis
(lb/ft3). Using equation 8, the mass per unit volume of carbon disulfide is calculated below:
mass/volume (lb/ft3)
(Cc) (MW/385.1 x 106)
(0.11 ppmv) (76/385.1 x 106) = 2.17 x 10"8 lb/ft3
Second, the mass per unit volume input is converted to a mass per unit of heat input using equation 9:
EF
(lb RSVft3 LFG) (FRCH4)"1 (He J1 [(MW So2)/MWRS_)] (mole SO^mole RS") (106)
(2.17 x 10"8 lb/ft3LFG) (ft3 LFG/0.55 ft3 CH4) (ft3 CH4/1,012 Btu) (64/76) (2/1) (106)
6.57 x 10"5 lb SCyMMBtu
The two steps above are repeated for each RS" species. The results are then used in equation 10 to
determine the overall S02 EF:
Total S02 EF
= z efso2
6.57 x 10"5 + 1.30 x 10"2 + 6.57 x 10"4 + 4.18 x 10"5 + 8.36 x 10"5 + 2.84 X 10"5 +
1.94 x 10"3 + 2.99 x 10"4 + 1.25 x 10"4 + 8.66 x 10"5
1.63 x 10"2 lb SO^MMBtu
Annual emissions can now be determined with equation 3:
Annual S02 emissions
[EF] [Qj] [HOP] [1/2,000]
(1.63 x 10"2 Ib/MMBtu) (26.15 MMBtu/hr) [8,760 (1 - 3/100) hr/yr] (ton/2,000 lb)
1.81 ton/yr
16
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Carbon Dioxide. C02 emissions are also determined by mass balance with equations 6, 11 through 14,
and equation 8. The amount of C02 contained in the collected LFG is combined with C02 formed during
the combustion of CH4 and NMOC. The carbon (in CH4 and NMOC), which is oxidized only to CO, is then
subtracted. The first step is to express the amount of LFG C02 collected (and hence emitted) by the
control system in terms of mass per unit of heat input (e.g., Ib/MMBtu). Using the C02 concentration from
table 5 and equation 6 (ncmb = 0 for C02);
C02 EF1 (Ib/MMBtu)
[Cc02] [MW/385.1 x 106] [FRCH4]"1 [HeJ' [106] [1 - Ticmb]
(450,000 ppmv) (44/385.1 x 10B) (ft3 LFG/0.55 ft3 CH4) (ft3 CH4/1,012 Btu) (106) (1 - 0)
92.4 lb C02/MM8tu
The second and third steps are used to estimate the amount of COz formed during the combustion of CH4
and NMOC. The methane input to the system is estimated using the methane concentration from table
5, equation 11, and T]cmb for CH4 (99.9 percent):
lb CH4/MMBtu
[CCH4] [MW/(385.1 x 106)] [FRCH4]"1 [HcJ1 [106] [ncmb]
(550,000 ppmv) (16/385.1 X 106) (ft3 LFG/0.55 ft3 CH4) (ft3 CH4/1,012 Btu) (106) (0.999)
41.0 lb CH4/MMBtu
Next, the methane input to the system is converted to C02 output using equation 12:
C02 EF2 (Ib/MMBtu)
[lb CH4/MMBtu] [MWC02/MWCH4] [mole COj/mole CH4]
(41.0 lb CH4/MMBtu) (44/16) (1/1)
113 lb C02/MMBtu
The same process is used to determine the amount of C02 formed from the combustion of NMOC using
the NMOC concentration from table 5, the average combustion control efficiency, and equations 11 and
12:
lb NMOC/MMBtu
[Cnmoc) PW/(385.1 x 106)] [FRCH4r1 [HcJ* [106] focrTlb]
(1,170 ppmv) (86/385.1 x 106) (ft3 LFG/0.55 ft3 CH4) (ft3 CH4/1,012 Btu) (106) (0.98)
0.46 lb NMOC/MMBtu
C02 EF3 (Ib/MMBtu)
[lb NMOC/MMBtu] [MWc02/MWnmoc] [6 mole CO^mole NMOC]
(0.46 lb NMOC/MMBtu) (44/86) (6/1)
1.41 lb COg/MMBtu
The fourth step is to determine the amount of C02 that needs to be subtracted out due to incomplete
combustion of the organics to CO. The CO EF for flares from table 2 is used in this step, along with
equation 13 to convert CO to the C02 equivalent:
17
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co2 ef4
[EFco] [MWC02/MWC0]
(0.168 lb CO/MMBtu) (44/28)
0.254 lb COg/MMBtu
Finally, equation 14 is used to determine the C02 EF for collected LFG:
C02 EFC0|
EF1 + EF2 + EF3 - EF4
92.4 ib/MMBtu + 113 Ib/MMBtu + 1.41 Ib/MMBtu - 0.264 Ib/MMBtu
207 Ib/MMBtu
Annual controlled emissions of C02 can now be estimated with equation 7:
C02 emissions (ton/yr)
{[C02 EFC0|] [Qj] [HOP] [1/2,000]}+ {[C02 ERucl] [1 - t1oo1]} + {[C02 ERUC|] [ncol] [SD]
" ^cmb^
{(207 Ib/MMBtu) (26.15 MMBtu/hr) (8497 hr/yr) (ton/2,000 lb)} + {(15,682 ton/yr)
(1 - 0.675)} + {(15,682 ton/yr) (0.675) (0.03) (1 - 0)
22,997 + 5,097 + 318
28,412 ton/yr
Table 7 provides a summary of the EFs and controlled emission rates for the flare example.
4.2.2 Emissions Resulting from LFG Utilization Using a RIC Engine
Emissions for the example landfill following installation of a LFG collection system and a RIC engine
utilization system are presented in this section. The RIC engine is assumed to be capable of consuming
the 26.15 MMBtu/hr heat input determined in Section 4.2.1 for the 783 ft3/min of LFG collected. The
utilization system is assumed to have a 93 percent availability or 7 percent SD. When the system is down,
the collected LFG is sent to an on-site flare. A summary of controlled emissions for the RIC engine
example is presented in table 8.
Secondary Compounds. Annual emissions of secondary compounds, such as NOx and CO are calculated
in similar fashion to those estimated for a flare (see Section 4.2.1). As for flares, annual emissions are
calculated using the EFs presented in table 2 and equation 3. For example, CO emissions from a RIC
engine would be determined as follows:
Annual emissions from the utilization system
[EFl [Qj] [HOP] [1/2,000]
[0.462 Ib/MMBtu] [26.15 MMBtu/hr] {8,760 hr/yr [1 - (7/100)]} [1/2,000]
= 49.2 ton/yr
During the RIC engine downtime, the back-up flare is operating and producing carbon monoxide. To
calculate emissions created during downtime, the CO flare emission factor from table 2 is used.
18
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TABLE 8. RIC ENGINE EXAMPLE: SUMMARY OF CONTROLLED AIR POLLUTANT
EMISSION FACTORS AND EMISSION RATES
Compound
Emission Factor, EFcol
Emission Rate
kg/kWh
Ib/kWh
Mg/yr
ton/yr
Criteria Pollutants/Ozone Precursors
Carbon Monoxide
2.08 x 10"3
4.58 x 10
45.9
50.6
Nitrogen Oxides
1.07 x 10"3
2.37 x 10
23.8
26.2
NMOC (as hexane), total
4.22 x 10"5
9.30 X 10
24.5
27.0
from LFG combustion
0.91
1.00
during System Downtime
0.07
0.08
from uncollected LFG
23.5
25.9
Sulfur Dbxide
7.35 x 10"5
1.62 X 10
1.70
1.87
Greenhouse Gases
Carbon Dioxide, total
25,203
27,781
from LFG combustion
0.926
2.04
19,907
21,943
during System Downtime
672
741
from uncollected LFG
4,624
5,097
Methane, total
2,059
2,270
from LFG combustion
1.85 X 10"4
4.07 X 10
3.97
4.38
during System Downtime
0.30
0.33
from uncollected LFG
2,055
2,265
Annual emissions from the backup flare
[EF] [Qj] [HOP] [1/2,000]
[0.168 Ib/MMBtu] [26.15 MMBtu/hr] [8,760 hr/yr (0.07)] [1/2,000]
= 1.35 ton/yr
Total annual emissions are the sum for the utilization device and the flare:
49.2 + 1.35
= 50.6 ton/yr
An EF for alternative energy comparison purposes (Ib/kWh), can be derived from the EF for the utilization
device above, equation 5, and the default heat rate for RIC engines from table 3. For CO:
EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1 h 06]
[0.462 Ib/MMBtu] [9,906 Btu/kWh] [1/106]
4.58 x 10~3 Ib/kWh
Emissions and EFs for CO and NOx are presented in table 8.
19
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Controlled Primary Emissions (NMOC and CH4). NMOC emissions are determined as above for flares.
Since the combustion efficiency for the RIC engine is assumed to be the same as for the flare (i.e., 98
percent), the EF in terms of heat input to the system will be the same. If a different combustion efficiency
had been guaranteed by the equipment vendor, then equatbn 6 would be used to derive an EF.
The EF, in mass per unit heat input, is then converted to mass per energy output with the plant heat rate,
HR, for RIC engines:
EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[9.39 x 10"3 Ib/MMBtu] [9,906 Btu/kWh] [1/106]
9.30 x 10"5 Ib/kWh
Annual emissions are calculated with equation 7 and a collection efficiency of 67.5 percent:
Annual emissions
{[EFJ [Qj] [HOP] [1/2,000]} + {[NMOC ERucl] [1 - t^,]} + {[NMOC ERucl] [SD] [r^,] [1 - Ticmb ]}
{[9.39 x 10"3 Ib/MMBtu] [26.15 MMBtu/hr] [8147 hr/yr] [1 ton/2,000 lb]} + {[79.7 ton/yr] [1 -
0.675]} + {[79.7 ton/yr] [0.07] [0.675] [1 - 0.98]}
= 1.00 ton/yr + 25.9 ton/yr -t- 0.08 ton/yr
27.0 ton/yr
The CH4 EF and emissions are determined using the same methods used to calculate the flare CH4 EF
and emissions. The EF in mass per unit heat input is converted to mass per energy output with the plant
heat rate, HR, for RIC engines:
EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[4.11 x 10"2 Ib/MMBtu] [9,906 Btu/kWh] [1/106]
4.07 x 10"4 Ib/kWh
Annual emissions are estimated with equation 7:
Annual emissions (ton/yr)
{[CH4 EF^JQiHHOPHl/2,000]} + {[CH4 ERuc|][1 - r,^]} + {[CH4 ERuc|] [nco,]] [SD] [1 - ncmb]}
{[4.11 x 10"2 Ib/MMBtu] [26.15 MMBtu/hr] [8,147 hr/yr] [1 ton/2,000 lb]} + {[6,970 ton/yr]
[1 - 0.675]} + {[6,970 ton/yr] [0.07] [0.675] [1 - 0.999]}
4.38 + 2,265 + 0.33
2,270 ton/yr
Controlled EFs and annual emission estimates of NMOC and CH4 are presented in table 8.
Sulfur Dioxide. Emissions of S02 are determined by mass balance with the assumption that all
control/utilization technologies will convert 100 percent of the RS" in the LFG to S02. Therefore the EF
results obtained above for a flare will be the same for an RIC engine (see Section 4.2.1). Annual
emissions are calculated for the RIC engine and the back-up flare. Since a flare is used during SD, HOP
for the RIC/flare combination is 8,760 hours per year.
20
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Annual S02 emissions
[EF] [Qj] [HOP] [1/2,000]
(1.63 x 10~2 ib/MMBtu) (26.15 MMBtu/hr) [8,760 hr/yr] (ton/2,000 lb)
= 1.87 ton/yr
The only calculation required is to convert the EF to a mass per energy output basis. Using equation 5
and the EF determined above for flares:
EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[1.63 x 10"2 Ib/MMBtu] [9,906 Btu/kWh] [1/106]
1.62 x 10"4 Ib/kWh
Carbon Dioxide. The determination of emission factors and emission rates is the same as that done for
flares in Section 4.2.1 with three exceptions; the system downtime used to calculate the HOP used to
calculate annual emissions for RIC engines (7 percent), the CO emissbn factor, and the flare back-up.
First, the only value that will change in deriving an emission factor is the CO EF for RIC engines from
table 2. The C02 equivalent EF (C02EF4) is derived with equation 13:
C02 EF4
[EFco] [MWC02/MWC0]
(0.462 lb CO/MMBtu) (44/28)
0.726 lb CO/MMBtu
Using equatbn 14 to determine the overall C02 EF:
CO, EFcol
EF1 + EF2 + EFg - EF4
92.4 Ib/MMBtu + 113 lb/MMBtu + 1.41 Ib/MMBtu - 0.726 Ib/MMBtu
206 Ib/MMBtu
C02 emissions (ton/yr)
ŦC02 EF0Q|] [Qj] [HOP] [1/2,000]}+ {[C02 ERJ [1 - ncol]} + {[C02 ERucl] [ncol] [SD] [1 - riomb]]
= {(206 Ib/MMBtu) (26.15 MMBtu/hr) (8,147 hr/yr) (ton/2,000 lb)} + {(15,682 ton/yr)
(1 - 0.675)} + {(15,682 ton/yr) (0.675) (0.07) (1 - 0)}
21,943 + 5,097 + 741
27,781 ton/yr
The emission factor above can be expressed in terms of energy output with equation 5:
EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[206 Ib/MMBtu] [9906 Btu/kWh] [1/106]
2.04 Ib/kWh
4.2.3 Emissions Resulting from LFG Utilization Using a Gas Turbine
Emissions for the example landfill following installation of a LFG collection and gas turbine utilization system
are presented in this Section. As with the RIC engine example, the turbine is assumed to be capable of
21
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consuming the 26.15 MMBtu/hr heat input determined in Section 4.2.1. Also, for this example system
downtime and combustion efficiencies are assumed to be the same as for RIC engines. EFs arid emission
rates are calculated in similar fashion to the flare and RIC engine examples given in Section 4.2.1 and
4.2.2, respectively. A summary of controlled emissbns for the gas turbine utilization option is presented
in table 9.
Secondary Compounds. As with RIC engines, annual emissions are calculated using the EFs presented
in table 2 and equation 3. For example, CO emissions from the gas turbine would be:
Annual emissions for the gas turbine plant
[EF] [Qj] [HOP] [1/2,000]
[9.54 x 10"2 Ib/MMBtu] [26.15 MMBtu/hr] [8,760 {1 - (7/100)} hr/yr] [1/2,000]
10.2 ton/yr
During the gas turbine downtime, the back-up flare is operating and producing carbon monoxide. To
calculate emissions created during the downtime, we use the CO flare emission factor:
Annual emissions for the flare
[EF] [Qj] [HOP] [1/2,000]
[0.168 Ib/MMBtu] [26.15 MMBtu/hr] [(8,760 hr/yr) (0.07)] [1/2,000]
= 1.35 ton/yr
Total annual CO emissions
10.2 + 1.35
= 11.6 ton/yr
An EF for alternative energy comparison purposes (Ib/kWh), can be derived from equation 5 and the default
heat rate for gas turbines in table 3. For CO:
EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[9.54 x 10"2 Ib/MMBtu] [14,247 Btu/kWh] [1 /106]
1.36 x 10"3 Ib/kWh
Emissions and EFs for the secondary compounds are presented in table 9.
Controlled Primary Emissions (NMOC and CH4). Since the combustion efficiency for gas turbines is
assumed to be the same as for RIC engines (i.e., 99.9 percent for CH4 and 98 percent for NMOC), the
NMOC and CH4 EF and annual emissions are determined as above for RIC engines (see Section 4.2.2).
For energy comparisons, the EF in mass per unit heat input is converted to mass per energy output with
the plant heat rate, HR, for gas turbines:
NMOC EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[9.39 x 10"3 Ib/MMBtu] [14,247 Btu/kWh] [1 /106]
1.34 x 10"4 Ib/kWh
22
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TABLE 9. GAS TURBINE EXAMPLE; SUMMARY OF CONTROLLED AIR
POLLUTANT EMISSION FACTORS AND EMISSION RATES
Compound
Emission Factor, EF^,
Emission Rate
kg/kWh
Ib/kWh
Mg/yr
ton/yr
Criteria Pollutants/Ozone Precursors
Carbon Monoxide
6.17 x 10"4
1.36 x 10~3
10.5
11.6
Nitrogen Oxides (as N02)
6.14 x 10"3
1.35 x 10"3
9.8
10.8
NMOC (as hexane), total
24.5
27.0
from LFG combustion
6.07 x 10"5
1.34 x 10-4
0.91
1.00
during System Downtime
0.07
0.08
from uncollected LFG
23.5
25.9
Sulfur Dioxide
1.05 X 10"5
2.32 X 10~4
1.70
1.87
Greenhouse Gases
Carbon Dioxide, total
25,300
27,888
from LFG combustion
1.34
2.95
20,004
22,050
during System Downtime
672
741
from uncollected LFG
4,624
5,097
Methane, total
2,059
2,270
from LFG combustion
2.66 X 10"4
5.86 x 10"4
3.97
4.38
during System Downtime
0.30
0.33
from uncollected LFG
2,055
2,265
CH4 EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[4.11 x 10"2 !b/MMBtu] [14,247 Btu/kWh] [1/106]
5.86 x 10"4 Ib/kWh
Controlled gas turbine EFs and annual emission estimates of NMOC and CH4 are presented in table 9.
Sulfur Dioxide. Emissions of S02 are determined by mass balance with the assumption that all
control/utilization technologies will convert 100 percent of the RS" in the LFG to SO?. Therefore, the results
obtained above for a RIC engine will be the same for a gas turbine (see Section 4.2.2). The only additional
calculation required is to convert the EF to a mass per energy output basis. Using equatbn 5 and the EF
determined above for flares:
EF (Ib/kWh)
[EF (Ib/MMBtu)] [HR] [1/106]
[1.63 x 10"2 Ib/MMBtu] [14,247 Btu/kWh] [1 /106]
2.32 x 10"4 Ib/kWh
Carbon Dioxide. The determination of a controlled emission factor and emission rate is the same as that
23
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done for RIC Engines in Section 4.2.2, since the assumptions for combustion efficiency and system
downtime are the same. The only difference that needs to be accounted for is the difference in CO
emission factors for equation 13:
COg EF4
[EFco] [MWC02/MWC0]
(9.54 x 10"2 lb CO/MMBtu) (44/28)
0.150 lb CCyMMBtu
Using equation 14 to determine the overall C02 EF:
C02 EFC0|
EF, + EF2 + EF3 - EF4
92.4 Ib/MMBtu + 113 Ib/MMBtu + 1.41 Ib/MMBtu - 0.150 Ib/MMBtu
207 Ib/MMBtu
C02 emissions (ton/yr)
{[C02 EFJ [Qs] [HOP] [1/2,000]}+ {[C02 ERucl] [1 - ncol]} + {[C02 ERucl] [ncol] [SD] [1 - nc
{(207 Ib/MMBtu) (26.15 MMBtu/hr) (8,147 hr/yr) (ton/2,000 lb)} + {(15,682 ton/yr)
(1 - 0.675)} + {(15,682 ton/yr) (0.675) (0.07) (1-0)
22,050 + 5,097 + 741
= 27,888 ton/yr
The gas turbine emission factor can be expressed in terms of energy output with equation 5 and the plant
heat rate for gas turbines:
EF (Ib/kWh)
,6i
[EF (Ib/MMBtu)] [HR] [1/101
[207 Ib/MMBtu] [14,247 Btu/kWh] [106]
2.95 Ib/kWh
4.2.4 Emissions Resulting from LFG Control Using a Boiler
Emissions for the example landfill following installation of a LFG collection system and boiler are presented
in this section. The boiler is assumed to be capable of consuming the 26.15 MMBtu/hr heat input
determined in Section 4.2.1 for the 783 ft3/min of LFG collected. Also, the combustion efficiencies and
system downtime assumptions used in the previous two sections are used here. A summary of controlled
emissions for the boiler example is presented in table 10.
Secondary Compounds. Annual emissions of secondary compounds, such as NOx and CO are calculated
in similar fashion to those estimated for a flare (see Section 4.2.1). As for flares, annual emissions are
calculated using the EFs presented in table 2 and equation 3. For example, CO emissions from a boiler
would be (assuming 7 percent system down-time):
Annual emissions for the boiler
[EF] [Qj] [HOP] [1/2,000]
[5.52 x 10"3 Ib/MMBtu] [26.15 MMBtu/hr] [8,760 hr/yr {1 - (7/100)}] [1/2,000]
= 0.588 ton/yr
24
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TABLE 10. BOILER EXAMPLE: SUMMARY OF CONTROLLED AIR POLLUTANT
EMISSION FACTORS AND EMISSION RATES
Compound
Emission Factor, EFco,
Emission Rate
kg/kJ
Ib/MMBtu
Mg/yr
ton/yr
Criteria Pollutants/Ozone Precursors
Carbon Monoxide
2.37 x 10'9
5.52 x 10"3
1.79
1.94
Nitrogen Oxides
1.23 x 10"Ū
2.85 x 10'2
3.42
3.77
NMOC (as hexane), total
24.5
27.0
from LFG combustion
4.04 x 10"9
9.39 x 10"3
0.91
1.00
during System D
0.07
0.08
from uncollected LFG
23.5
25.9
Sulfur Dioxide
7.01 x 10"9
1.63 X 10"2
1.70
1.87
Greenhouse Gases
Carbon Dioxide, total
25,300
27,888
from LFG combustion
8.87 x 10"5
206
20,004
22,050
during System Downtime
672
741
from uncollected LFG
4,624
5,097
Methane, total
2,059
2,270
from LFG combustion
1.77 x 10~8
4.11 x 10"2
3.97
4.38
during System Downtime
0.30
0.33
from uncollected LFG
2,055
2,265
During the boiler downtime, the back-up flare is operating and producing carbon monoxide. To calculate
emissions created during the downtime, we use the CO flare emission factor from table 2.
Annual emissions from the flare back-up
[EF] [QJ [HOP] [1/2,000]
[0.168 Ib/MMBtu] [26.15 MMBtu/hr] [8,760 hr/yr 0.07] [1/2,000]
1.35 ton/yr
Total annual CO emissions
0.588 + 1.35
= 1.94 ton/yr
Emissions and EFs for the other secondary compounds are presented in table 10.
Controlled Primary Emissions (NMOC and CH^. The NMOC and CH4 EF and annual emissions are
determined as above for RIC engines (see Section 4.2.2). Controlled LFG boiler EFs and annual emission
estimates for NMOC and CH4 are presented in table 10.
Sulfur Dioxide. Emissions of S02 are determined by mass balance with the assumption that all
control/utilization technologies will convert 100 percent of the RS" in the LFG to S02. Therefore the results
25
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obtained above (Section 4.2.2) for a RIC engine will be the same for a boiler.
Carbon Dioxide. The determination of emission factors and emission rates is the same as that done for
RIC engines in Section 4.2.2. The only difference is that the CO emission factor for boilers needs to be
used in equation 13:
co2 ef4
[EFco] [MWca>/MWco]
(5.52 x 10"3 lb CO/MMBtu) (44/28)
8.67 x10"3 lb COg/MMBtu
Using equation 14 to determine the overall C02 EF:
C02 EFco|
EFt + EF2 + EF3 - EF4
92.4 Ib/MMBtu + 113 Ib/MMBtu + 1.41 Ib/MMBtu - 0.0087 Ib/MMBtu
207 Ib/MMBtu
Annual C02 emissions are calculated as for the previous two utilization options:
{[C02 EFcol] [Qj] [HOP] [1/2,000]}+ {[C02 ERuc|] [1 - iicol]} + {[C02 ERuol] hco|] [SD] [1 - ncmb]}
{(207 Ib/MMBtu) (26.15 MMBtu/hr) (8,147 hr/yr) (ton/2,000 lb)} + {(15,682 ton/yr)
(1 - 0.675)} + {(15,682 ton/yr) (0.675) (0.07) (1 - 0)}
22,050 + 5,097 + 741
27,888 ton/yr
4.3 Deriving Emissions for Alternative Energy Sources
Emission factors for alternative energy sources, presented in terms of either heat input or energy output
consistent with those developed in Section 4.2, are needed to make comparisons associated with the use
of LFG utilization equipment and other sources of energy. This section discusses sources of data needed
to develop comparison EFs and emission estimates. This discussion pertains to fossil fuels including coal,
residual and distillate oils, and natural gas.
As with determining EFs and emission estimates for LFG utilization and control, site-specific data will
provide the most accurate comparisons. A State or local air agency should be able to provide EFs for local
electricity generation sources, such as natural gas or coal-fired power plants. If these EFs are not
presented in the same terms as those described in Section 3, they can be converted with the data and
conversion factors presented below.
In the absence of site-specific emissions data from local utilities, EFs presented in EPA's AP-42,23 or
obtained from local air pollution control agencies can be used. AP-42 provides comprehensive emissions
data on criteria pollutants and their precursors and some data on GHGs. For the assessment of alternative
energy sources presented below, AP-42 is used as the primary source of emissions data.
Table 11 lists emission factor conversion data for the EFs presented in AP-42 along with fuel sulfur and
carbon content. EFs for coal combustion sources are typically given in lb/ton or the metric units of kg/Mg
of coal consumed. To convert this EF to units of heat input, equation 15 can be used. Fuel densities are
included in table 11 for instances where the EF must be converted from units of mass emissions per mass
of liquid or gaseous fuel (e.g., lb COj/lb residual oil).
26
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TABLE 11. EMISSION FACTOR CONVERSION DATA AND FUEL PARAMETERS*
Fuel Type
HHV*
Density*
Sulfur*
Carbon**
kJ
kg
% weight
% weight
(MMBtu)
(lb)
Bituminous/
3.02 x 107/Mg
1 kg/kg
0.6 - 5.4
66.6
Subbituminous coal
(26/ton)
(1/lb)
Anthracite coal
2.85 x 107/Mg
1 kg/kg
0.5 - 1.0
79.7
(24.6/ton)
(1/lb)
Residual oil
4.18 x 104/l
0.944/I
0.5 - 4.0
N/A
(0.15/gal)
(7.88/gai)
Distillate oil
3.90 x 104/I
0.845/I
0.2 - 1.0
85.6
(0.14/gal)
(7.05/gal)
Natural gas
3.91 x 1013/m3
0.673/m3
8.15 x 10"4+
N/A
(1.05 x 10"3/ft3)
(1/23.8 ft3)
* Reference 23.
** Reference 24.
t Reference 25.
I = liters; gal = gallons; m = meters.
N/A = Not available or applicable.
EF (Ib/MMBtu) = [EFJ [HHV]"1 [106] (eq. 15)
Where: EFU = emission factor based on units of fuel consumed (lb/unit)
HHV = higher heating value of the fuel (Btu/unit)
106 = conversion factor, Btu to MMBtu
After any necessary conversions have been made to the EFs for the comparison energy projects, direct
comparisons can be made to those calculated for LFG control using a flare or LFG utilization with a boiler
or process heater. To develop useful comparisons for LFG utilization projects that produce electricity,
equatbn 5 should be used along with an appropriate HR value to convert the EFs based on heat input to
EFs based on power output. Values of HR for the comparison technologies assessed in this document are
presented in table 12. These values were obtained from the U.S. Department of Energy [(DOE)].26 DOE
publishes data on the annual average nationwide plant HR for fossil fuel-fired steam electric plants. For
the most recent year, 1993, the average HR was 10,352 Btu/kWh. DOE also publishes data on other
electricity generation technologies. An average plant heat was also developed for natural gas-fired turbines
using the DOE data (see table 12). As with all of the data presented in this document, site-specific data
on the plant HRs of local utilities should be selected for use over the default values in table 12, whenever
available.
The following three Sections, 4.3.1 through 4.3.3, present EFs and emission estimates for four typical
alternative energy utilization technologies; a coal-fired steam power plant, a natural gas-fired turbine power
plant, and an industrial boiler fired on either natural gas or distillate oil.
27
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TABLE 12. DEFAULT PLANT HEAT RATES FOR COMPARISON TECHNOLOGIES*
Utilization Technology
Heat Rate
kJ/kWh
Btu/kWh
Fossil fuel-fired steam electric plants
10,932
10,352
Natural gas-fired turbines
15,323
14,510
Reference 26.
4.3.1 Coal-Fired Steam Power Plant
Emission factors and emission rates for a pulverized coal (bituminous/subbituminous), dry bottom, wall-fired
boiler were determined based on emission rates contained in Section 1.1 of AP-42, and fuel parameters
presented in table 11 of this document. Certain assumptions were made to convert units of EFs into units
directly comparable to the EFs developed for LFG utilization technologies, and to estimate emissions from
the EFs. These assumptions are as follows:
Heat input to plant
Higher heating value of
bituminous/subbituminous coal
Hours of operation
Sulfur content
Carbon content
Plant HR
Control efficiencies
26.15 MMBtu/hr (equivalent to the example assessment
prepared for the LFG utilization technologies, see Section
4.2)
26 MMBtu/ton 23
8,147 hr/yr (based on 24 hr/day, 365 day/yr, 7 percent
down-time)
3 percent by weight (mid-point of sulfur content reported in
AP-42, and shown in Table 11)
66.6 percent by weight 24
1.035 x 10"2 MMBtu/kWh 26
80 percent control of S02 for a wet scrubber, and 25
percent control of NOx for staged combustion.23
The results of the conversions of AP-42 EFs for a coal-fired boiler into units of kg/kJ, Ib/MMBtu, kg/kWh,
and Ib/kWh, and calculation of emission rates (Mg/yr, ton/yr) are shown in table 13. Calculation of S02
emissions is dependent on the sulfur content of the fuel. The method used to calculate S02 emissions
from coal combustion is shown below.
Uncontrolled AP-42 emission factor = 38 (S)(1 - tj) lb SCyton fuel combusted
Where: S = weight percent sulfur content as fired
i1 = control efficiency
percent sulfur for bituminous coal = 3 percent
percent control due to wet scrubber = 80 percent
Controlled S02 emissions = 38(3)(1 - 0.80) = 22.80 lb S02 /ton coal combusted
28
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TABLE 13. COAL-FIRED STEAM POWER PLANT: SUMMARY OF EMISSION FACTORS
AND EMISSION RATES
Compound
Emission Factor
Emission Rate
kg/kJ
Ib/MMBtu
kg/kWh
Ib/kWh
Mg/yr
Ton/yr
Criteria Pollutants/Ozone Precursors
Carbon
8.26 x 10"9
1.92 x 10"2
9.04 x 10"5
1.99 x 10"4
1.86
2.05
Nitrogen
2.70 X 10"7
0.63
2.94 x 10"3
6.48 x 10*3
60.6
66.7
NMOC
9.93 X 10"10
2.31 x 10"3
1.45 x 10"5
2.39 x 10"s
0.22
0.25
Sulfur
3.77 xlO"7
0.88
4.12 x 10"3
9.08 x 10"3
84.8
93.4
Greenhouse Gases
Carbon
8.09 x 10"5
188
0.88
1.94
18,180
20,026
Methane
6.61 X 10"10
1.54 x 10"3
7.23 X 10"6
1.59 x 10"5
0.15
0.16
4.3.2 Natural Gas-Fired Turbine
Emission factors and emission rates for a gas-fired turbine controlled with selective catalytic reduction
(SCR) with water injection were determined based on emission rates contained in Section 3.1 of AP-42,
and fuel parameters presented in table 11 of this document. Certain assumptions were made to convert
units of EFs into units directly comparable to the EFs developed for LFG utilization technologies, and to
estimate emissions from the EFs. These assumptions are as follows:
Heat input to plant
26.15 MMBtu/hr (equivalent to the example assessment
prepared for the LFG utilization technologies, see Section
4.2)
Higher heating value of
natural gas
Hours of operation
Sulfur content
1,050 MMBtu/MMcf23
8,147 hr/yr (based on 24 hr/day, 365 day/yr, 7 percent
down-time)
8.150 x 10"4 percent by weight.25 Emission factor for S02
= 259(S)
Plant HR
Control efficiencies
14,510 Btu/kWh (table 12)
AP-42 emission factors represent controlled emissions
(SCR control efficiencies for NOx typically range from 70-
90 percent)27
The results of the conversions of AP-42 EFs for a gas-fired turbine into units of kg/kJ, Ib/MMBtu, kg/kWh,
and Ib/kWh, and calculation of emission rates (Mg/yr, ton/yr) are shown in table 14.
29
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TABLE 14. NATURAL GAS TURBINE POWER PLANT: SUMMARY OF EMISSION FACTORS
AND EMISSION RATES
Compound
Emission Factor
Emission Rate
kg/kJ
Ib/MMBtu
kg/kWh
Ib/kWh
Mg/yr
Ton/yr
Criteria Pollutants/Ozone Precursors
Carbon
Monoxide
3.60 x 10"9
8.40 x 10"3
5.53 x 10"5
1.22 x 10"4
0.81
0.89
Nitrogen
Oxides
1.29 x 10"Ū
3.00 X 10'2
1.97 x 10~4
4.35 x 10"4
2.90
3.20
NMOC
1.38 x 10"9
3.20 x 10"3
2.11 x 10"s
4.64 x 10"5
0.31
0.34
Sulfur
Dioxide
3.29 x 10"10
7.66 x 10"4
5.04 x 10"6
1.11 x 10"5
7.40 x 10"2
8.16 x 10"2
Greenhouse Gases
Methane
6.02 x 10"9
1.40 x 10"2
9.22 X 10 s
2.03 X 10"4
1.35
1.49
Carbon
4.82 X 10"5
112
0.74
1.63
10,823
11,929
Dioxide
4.3.3 Industrial Boiler
Emission factors and emission estimates are derived in this section for an industrial boiler fired on either
natural gas or distillate oil. As with the energy alternatives above, the industrial boiler is assumed to
consume the same amount of energy as the LFG control/utilization options discussed in Section 4.2.
Natural Gas-Fired Boiler Emission factors and emission rates for a industrial gas-fired external
combustion boiler were determined based on emission rates contained in Section 1.4 of AP-42 and fuel
parameters presented in table 11 of this document. Certain assumptions were made to convert units of
emission factors into units directly comparable to the emission factors developed for LFG utilization
technologies, and to estimate emissions from the EFs. These assumptions are as follows:
Heat input to plant
26.15 MMBtu/hr (per the analysis done on sample LFG
utilization technologies, see Section 4.2)
Higher heating value of
natural gas
1,050 MMBtu/MMft3 (table 11)
Hours of operation
Sulfur content
Control efficiencies
8,147 hr/yr (based on 24 hr/day, 365 day/yr, 7 percent
down-time)
25
8.150 x 10 percent by weight1
Not applicable, boiler is uncontrolled. AP-42 emission
factors represent uncontrolled emissions.
The results of the conversions of AP-42 EFs for a natural gas-fired external combustion boiler into units
of kg/kJ and Ib/MMBtu, and calculation of emission rates (Mg/yr, ton/yr) are shown in table 15. It is
important to note that all of the emissions estimated for this example represent uncontrolled emissions.
In certain areas (i.e., ozone nonattainment areas), control efficiencies for specific pollutants should be used
30
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TABLE 15. NATURAL GAS-FIRED BOILER: SUMMARY OF EMISSION FACTORS
AND EMISSION RATES
Compound
Emission Factor
Emission Rate
kg/kJ
Ib/MMBtu
Mg/yr
Ton/yr
Criteria Pollutants/Ozone Precursors
Carbon Monoxide
1.43 x 10"8
3.33 x 10~2
3.22
3.55
Nitrogen Oxides
5.74 x 10"B
0.133
12.9
14.2
NMOC
1.14 x 10"9
2.65 x 10"3
0.256
0.282
Sulfur Dbxide
2.46 x 10"10
5.71 x 10~4
5.52 x 10~2
6.09 x 10"2
Greenhouse Gases
Carbon Dbxide
4.92 x 10"5
114
11,023
12,143
Methane
1.24 x 10'9
2.87 x 10"3
0.278
0.306
to adjust the uncontrolled EF to a controlled EF (see equation 4). As an example for natural gas
combustion, NOx controls, such as low-NOx burners or selective catalytic reduction, may be required on
industrial boilers in ozone nonattainment areas. AP-42 contains information on pollution control efficiencies
for common control technologies.23
Distillate Oil-Fired Boiler Emission factors and emission rates for a distillate oil-fired boiler were
determined based on emission rates contained in Section 1.3 of AP-42, and fuel parameters presented in
table 11 of this document. Certain assumptions were made to convert units of EFs into units directly
comparable to the EFs developed for LFG utilization technologies, and to estimate emission rates from the
EFs. These assumptions are as follows:
Heat input to plant
Higher heating value of
distillate oil
Hours of operation
Carbon content
Sulfur content
Control efficiencies
26.15 MMBtu/hr (per analysis done on sample LFG
utilization technologies, see Section 4.2)
140 MMBtu/1000 gal
23
8,146 hr/yr (based on 24 hr/day, 365 day/yr, 7 percent
down-time).
85.6 percent (see table 11). C02 emission factor = 259(C)
lb/10 gal distillate oil.
0.6 percent by weight25 (mid-point of sulfur content
reported in AP-42, and shown in Table 11).
Not applicable, boiler is uncontrolled. AP-42 factors
represent uncontrolled emissions.
31
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The AP-42 emission factor for C02 is dependent on the carbon percentage of the fuel. The calculation of
uncontrolled C02 emissions is given below:
Uncontrolled AP-42 emission factor = 259(C) lb C02 /103 gallon distillate oil
Where: C = weight percent carbon content of fuel
percent carbon for distillate oil = 85.6 percent
Uncontrolled C02 emissions = 259(85.6) = 22,170 !b COg/IO3 gallon distillate oil
The results of the emission factor conversions of AP-42 emission factors for a distillate oil-fired boiler into
units of kg/kJ and Ib/MMBtu, and calculation of emission rates (Mg/yr, ton/yr) are shown in table 16. As
with the natural gas boiler example given above, it is important to adjust uncontrolled EFs (see equatbn 4)
with the appropriate control efficiency in situations where an air pollution control is required or in use.
AP-42 contains information on pollution contra! efficiencies for common control technologies.23
TABLE 16. DISTILLATE OIL-FIRED BOILER: SUMMARY OF EMISSION FACTORS
AND EMISSION RATES
Compound
Emission Factor
Emission Rate
kg/kJ
Ib/MMBtu
Mg/yr
Ton/yr
Criteria Pollutants/Ozone Precursors
Carbon Monoxide
1.54 x 10"B
3.57 x 10"2
3.45
3.80
Nitrogen Oxides
6.15 x 10"8
0.143
13.8
15.2
NMOC
1.05 x 10"9
2.43 x 10-3
0.235
0.259
Sulfur Dioxide
2.62 x 10 7
0.609
58.8
64.8
Greenhouse Gases
Carbon Dioxide
6.81 x 10'5
158
15,278
16,830
Methane
6.64 x 10"10
1.54 X 10~3
0.149
0.164
4.4 Example LFG Control and Utilization Comparison Summary
Comparisons of emission factors and annual emission estimates developed in the previous three Sections
are presented in tables 17 through 21. The values presented in these tables should not be construed to
represent typical emissions for each listed industry nor should they be considered to represent the typical
differences in emissions between utilization options or alternative energy sources. The values presented
in the tables below and the differences between the various sources could change significantly depending
on site-specific conditions. The tables are presented in order to illustrate how the estimates developed in
the previous Sections can be presented to decision makers.
Table 17 provides a summary of emission factors developed in the previous two Sections for the electricity
generating utilization options and applicable energy alternatives. As discussed earlier, the EFs derived for
LFG control/utilization (i.e., EFC0|) only include emissions associated with the collected LFG. Table 18
summarizes the annual emissions for these sources and also a flare control. Annual emission estimates
are based on an equivalent energy input to all sources (26.15 MMBtu/hr). Finally, an estimate of the
annual power produced for each source based on this equivalent energy input is provided.
32
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TABLE 17. COMPARISON OF LFG UTILIZATION AND ALTERNATIVE ENERGY
SOURCE EMISSION FACTORS
Emission Factor (Ib/kWh)
Pollutant
LFG Utilization
Alternative Energy Source
RIC Engine
Gas Turbine
Coal-Fired Steam
Power Plant
Natural Gas
Turbine Power
Plant
CO
45.8 X 10~4
13.6 x 10"4
1.99 x 10"4
1.22 x 10"4
NOx
23.7 x 10-4
13.5 x 10-4
64.8 X10"4
4.35 x 10"4
NMOC
9.30 X 10"5
13.4 x 10"s
2.39 x 10-5
4.64 x 10"5
so2
16.2 x 10-5
23.2 x 10-5
908 x 10"5
1.11 x 10"5
eg
o
o
2.04
2.95
1.94
1.63
ch4
40.7 x 10"5
58.6 X 10"5
1.59 X 10"s
20.3 x 10"5
Tables 19 and 20 provide a similar comparison for an LFG boiler with two alternative energy sources. The
emission factors and annual emission estimates for the LFG boiler have been adjusted upward by
12 percent as discussed in Section 3.1 to account for the lower heat output typically encountered with the
use of LFG fuel.
Table 21 provides a comparison of annual uncontrolled versus controlled emissions from the example
landfill. The annual emissions differ from those presented in the tables above since emissbns from both
collected and uncollected LFG are included (i.e., assumptions include 90 percent of the landfill under the
influence of the collection system which operates at 75 percent efficiency).
33
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TABLE 18. COMPARISON OF ANNUAL EMISSIONS: LFG CONTROL/UTILIZATION
AND ALTERNATIVE ENERGY SOURCES
Annual Emissions (ton/yr)*
Pollutant
Flare/LFG
Control
RIC Engine/
LFG
Utilization**
Gas Turbine/
LFG
Utilization**
Coal-Fired
Steam
Power Plant
Natural Gas
Turbine
Power Plant
CO
18.7
50.6
11.6
2.05
0.89
NOx
10.1
26.2
10.8
66.7
3.20
NMOC
2.65
1.08
1.08
0.25
0.34
S02
1.81
1.87
1.87
93.4
0.08
CM
O
o
23,315
22,684
22,791
20,026
11,930
CH/
4.57
4.71
4.71
0.16
1.49
Annual Energy
Produced (kWh)
0
2.15 x 107
1.50 X 107
2.06 X 107
1.47 X 107
Based on 26.15 MMBtu/hr heat input, 3 percent down-time for flare, 7 percent down-time for all other sources.
Includes emissions from flare backup during 7 percent system down-time.
Emission estimates for CH,, are significantly higher for the LFG control/utilization due to the default combustion
efficiency of 99.9 percent. In reality, these systems can likely achieve efficiencies of greater than 99.99 percent
TABLE 19. COMPARISON OF LFG UTILIZATION AND ALTERNATIVE ENERGY
SOURCE EMISSION FACTORS
Pollutant
Emission Factor (Ib/MMBtu)
LFG
Boiler*
Alternative Energy Source
Natural Gas-Fired
Boiler
Distillate Fuel-
Fired Boiler
CO
6.27 x 10"3
33.3 X 10"3
35.7 x 10"3
NOx
3.24 x 10"2
13.3 x 10'2
14.3 x 10*2
NMOC
10.7 x 10"3
2.65 x 10"3
2.43 X 10"3
so2
183 x 10"4
5.71 x 10"4
6090 x 10"4
co2
235
114
158
O
X
Ķe.
4.67 x 10"3
2.87 x 10"3
1.54 X 10"3
EFs have been adjusted upward 12 percent to reflect lower heat output with the use of LFG.
Conservative combustion efficiencies for NMOC (98%) and CH4 (99.9%) were assumed.
34
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TABLE 20. COMPARISON OF ANNUAL EMISSIONS: BOILER LFG CONTROL
AND ALTERNATIVE ENERGY SOURCES
Pollutant
Annual Emissions (ton/yr)*
Flare/LF Gas
Control
Landfill Gas
Fired Boiler
Natural Gas
Fired Boiler
Distillate Fuel
Fired Boiler
CO
18.7
1.94
3.55
3.80
NOx
10.1
3.77
14.2
15.2
NMOC
2.65
1.08
0.282
0.259
so2
1.81
1.87
6.09 x 10"2
64.8
co2
23,315
22,791
12,143
16,830
**
ch4
145.6
4.71
0.306
0.164
Based on 26.15 MMBtu/hr heat input, 3 percent down-time for flare, 7 percent down-time for all
other sources.
Emission estimates for CH4 are significantly higher for the LFG control/utilization due to the
default combustion efficiency of 99.9 percent. In reality, these systems can likely achieve
efficiencies of greater than 99.99 percent.
TABLE 21. COMPARISON OF ANNUAL EMISSIONS: UNCONTROLLED VERSUS
CONTROLLED LANDFILL
Pollutant
Annual Emissions (ton/yr)*
Uncontrolled
Landfill
Flare/LFG
Control
RIC Engine/
LFG Utilization
Gas Turbine/
LFG Utilization
Boiler/
LFG Control
CO
N/A
18.7
50.6
11.6
1.94
NOx
N/A
10.1
26.2
10.8
3.77
NMOC
79.7
28.5
27.0
27.0
27.0
so2
N/A
1.81
1.87
1.87
1.87
co2
15,682
28,412
27,781
27,888
27,888
ch4
6,970
2,411
2,270
2,270
2,270
* includes emissions from collected and uncollected LFG.
N/A Not applicable. Emissions of this compound are only associated with the combustion of
LFG.
35
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5. ISSUES REQUIRING ADDITIONAL ANALYSIS
Refinements to the data presented in this document and supporting documentation will likely take place
in the near future, as new data are made available to EPA by industry and the regulated community. A
revision to the AP-42 section on landfills is expected within the next 1 to 2 years. Additional data will be
needed to refine the estimates of key factors such as the default concentrations of LFG constituents (in
AP-42). Also, defaults for secondary compound emission factors and primary pollutant control efficiencies
presented here and in AP-42 require refinement.
An assessment of primary and secondary hazardous air pollutants (HAPs) may be required as part of a
LFG control/utilization impacts assessment. AP-42 contains some information on determining emissions
of primary HAPs (e.g., toluene, trichloroethane) from landfills, but none on secondary HAPs from
control/utilization projects (e.g., polycyclic aromatic hydrocarbons, formaldehyde).3 In addition, HAP
emissions data for comparison energy projects are often lacking in AP-42. Supplemental data on HAP
emissions for LFG control/utilization and comparison energy projects may be found in EPA's FIRE data
base.28
Emissions data for emerging LFG utilization technologies are lacking. Technologies currently undergoing
field demonstrations include the conversion of LFG to compressed natural gas for vehicle fuel, conversion
of LFG to methanol for use either as an industrial feedstock or vehicle fuel, and processing of LFG to
provide methane for use in fuel cells to generate electricity. Also, sterling and organic rankine cycle
engines, are also being reviewed as potential technologies for the utilization of LFG.
36
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