EPA-600/R-95-035
March 1995
LANDFILL GAS ENERGY UTILIZATION
EXPERIENCE: DISCUSSION OF
TECHNICAL AND NON-TECHNICAL
ISSUES, SOLUTIONS, AND TRENDS
by
Michiel Doom
E.H. Pechan & Associates, Inc.
3500 Westgate Drive, Suite 103
Durham, North Carolina 27707
%
John Pacey
F.H.C., Inc.
Pebble Beach, California 93953
Don Augenstein
I.E.M.
Palo Alto, California 94306
EPA Contract No. 68-D1 -0146
Work Assignment Nos. 1/015, 1/022, 2/031, and 2/034
Project Officer
Susan Thorneloe
Air and Energy Engineering Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Prepared for
U.S. Environmental Protection Agency
Office of Research and Development
Washington, DC. 20460
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before comple
1. REPORT NO.
EPA-600/R-95-035
2.
PB95-188108
4. TITLE ANDSUBTITLE
Landfill Gas Energy Utilization Experience: Discus-
sion of Technical and Non-technical Issues, Solutions,
and Trends
5. REPORT DATE
March 1995
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
M. Doom (Pechan), J. Pacey (F. H. C. , Inc.), and
D. Augenstein (I.E.M.)*
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
E.H. Pechan and Associates, Inc.
3500 Westgate Drive
Durham, North Carolina 27707
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.gg- DJ-Q146
Tasks 1/15,1/22, 2/31, and
2/34 (Pechan)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 1/92-9/94
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES AEERL project officer is Susan A. Thorneloe, Mail Drop 63, 919/
541-2709. (*) F.H. C. ,Inc., Pebble Beach, CA 93953; and J. E. M., Palo Alto, CA
94306.
16. ABSTRACT rj-^g repOrf discusses technical and non- technical considerations associated
with the development and operation of landfill gas to energy projects. Much of the
report is based on interviews, and site visits with the major developers and operators
of the more than 110 projects in the U. S. The report also provides the history and
trends of the landfill gas industry in the U.S. Graphs illustrate how the influence of
reciprocating internal combustion (RIC) engines, compared to other utilization op-
tions, has steadily increased over time. The report summarizes information on new
landfill gas utilization technologies, including vehicular fuel systems and fuel cells.
Overall results of programs to demonstrate the operational feasibility of innovative
technologies appear quite promising. For example, fuel cell technology for landfill
gas has many potential advantages over conventional technologies, including its high
energy efficiency, minimal by-product emissions, and minimal labor and mainten-
ance. The use of fuel cells may be economically feasible before the turn of the cen-
tury. Some of the non-technical problems and solutions described in the report are
associated with the development of energy utilization options including project eco-
nomics, barriers, and incentives.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution Fuel Cells
Earth Fills Greenhouse Effect
Energy Conversion Techniques
Gases
Energy
Automotive Fuels
Pollution Control
Stationary Sources
Landfill Gas
13B
13 C
10A
07D
14G
21D
10 B
04A
3. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
292
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
M-12
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NOTICE
This document has been reviewed in accordance with
U.S. Environmental Protection Agency policy and
approved for publication. Mention of trade names
or commercial products does not constitute endorse-
ment or recommendation for use.
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ABSTRACT
Clean Air Act (CAA) regulations under consideration for new and existing municipal solid waste landfills are
expected to require approximately 500 to 700 sites to install and maintain a landfill gas extraction and
control facility to reduce landfill emissions, which include nonmethane organic compounds, toxics, and
greenhouse gases. The Air and Energy Engineering Research Laboratory (AEERL) of the United States
Environmental Protection Agency (EPA) is conducting ongoing research to provide information on energy
conversion options for landfill gas utilization as a means of assisting landfill owner/operators that may be
affected by the CAA regulations.
This report is a follow on to an earlier publication entitled: "Landfill Gas Energy Utilization: Technology
Options and Case Studies" (Augenstein and Pacey, 1992). The 1992 publication provides information on
the different options for landfill gas utilization which are illustrated by case studies. The focus of this new
report is on technical and non-technical considerations associated with the development and operation of
landfill gas to energy projects. Much of the information used to generate this report is from interviews and
site visits with the major developers and operators of the more than 110 projects in the U.S. This report
also provides the history and trends of the landfill gas industry in the U.S. Graphs illustrate how the use
of reciprocating internal combustion (1C) engines, compared to other utilization options, has steadily
increased over time.
Landfill gas is a medium heating value fuel [approximately 500 British thermal units per standard cubic foot
(Btu/scf)], and can contain corrosive compounds and particulates. The gas may be used in direct heating
applications (i.e., boilers or kilns), in reciprocating engines and turbines to produce electricity, or it may be
purified to pipeline quality gas, or for use in fuel cells. This report identifies the potential difficulties that
may be encountered in developing a landfill gas to energy project and presents possible solutions that have
been found through the experience of the landfill gas to energy industry. Possible remedies to typical
technical landfill gas issues addressed in this report are: 1) material modifications; 2) condensate
management; 3) use of special oils (in 1C engines); and 4) engine adjustments (in 1C engines).
Some of the non-technical problems and solutions described in this report are associated with the
development of energy utilization options including project economics, barriers, and incentives. Two new
programs that may provide incentives are described. The information presented on non-technical barriers
is primarily based on the experience of private U.S. landfill gas project developers and operators and is not
intended to give a comprehensive overview of all perspectives on landfill gas utilization.
Ongoing research by EPA and others is aimed at tracking and developing new options for landfill gas
utilization. This report summarizes information on new landfill gas utilization technologies, including
vehicular fuel systems and fuel cells. Overall results of programs to demonstrate the operational feasibility
of innovative technologies appear quite promising. For example, the fuel cell technology for landfill gas
appears to have many potential advantages over conventional technologies including its high energy
efficiency, minimal by-product emissions and minimal labor and maintenance. The use of fuel cells may
be economically feasible before the turn of the century.
Additional information is provided in various appendices. Appendix E presents international landfill gas
experience. In Appendix H, the attributes of various proven technologies for generating electricity while
utilizing landfill gas as a fuel are discussed. Appendix I details landfill gas turbines, whereas Appendix J
describes a demonstration project to convert landfill gas into vehicle fuel. An EPA memo dated July 1994
providing the EPA's New Source Review policy which regards landfill gas to energy projects as potential
pollution prevention sources is included in Appendix K. Appendices L and M focus on non-technical issues
such as the sale of electricity from landfill gas projects and alternative energy regulatory policies.
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TABLE OF CONTENTS
ABSTRACT i i i
TABLES . . Vil
FIGURES VI1
ACKNOWLEDGEMENTS vi i i
ABBREVIATIONS i X
CONVERSIONS X
METRIC PREFIXES xi
1. INTRODUCTION 1
1.1 BACKGROUND 1
1.2 PURPOSE OF THIS REPORT 2
1.3 DEVELOPMENT OF THE LANDFILL GAS INDUSTRY AND TRENDS 3
2. LANDFILL GAS PROPERTIES 9
2.1 COMPOSITION AND CONTAMINANTS 9
2.1.1 Condensate 10
2.1.2 Deposits 10
2.1.3 Other Potential Issues 11
2.2 VARIABLE FLOW AND ENERGY CONTENT 11
3. TECHNICAL ISSUES, SOLUTIONS, AND FIELD EXPERIENCE 13
3.1 GENERAL : . 13
3.1.1 Pressure Considerations 14
3.1.2 Material Modifications 14
3.1.3 Condensate Management 15
3.1.4 Aerosol and Paniculate Removal 17
3.2 RECIPROCATING INTERNAL COMBUSTION ENGINES 17
3.2.1 Oil Selection and Management 17
3.2.2 Engine Adjustments 18
3.2.3 Lean-Burn 1C Engines 19
3.2.4 Field Experience 1C Engines 20
3.3 GAS TURBINES 24
3.3.1 Field Experience Turbines 24
3.4 BOILERS 27
3.4.1 Field Experience Boilers 28
3.5 LANDFILL GAS PURIFICATION TO PIPELINE QUALITY 29
4. NON-TECHNICAL CONSIDERATIONS 30
4.1 BARRIERS 31
4.1.1 Selected Case Histories 35
4.2 INCENTIVES 37
4.2.1 New Initiatives 41
5. EMERGING TECHNOLOGIES 42
5.1 COMPRESSED LANDFILL METHANE AS VEHICULAR FUEL 43
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5.2 LANDFILL METHANE CONVERSION TO METHANOL 43
5.3 LANDFILL METHANE IN FUEL CELLS 44
6. INDEX 46
7. REFERENCES : 48
APPENDIX A: ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY
UTILIZATION: TECHNOLOGY OPTIONS AND CASE STUDIES A-1
APPENDIX B: FURTHER READING B-1
APPENDIX C: LIST OF DEVELOPERS AND OPERATING COMPANIES C-1
APPENDIX D: INTERVIEW SUMMARIES D-1
TECHNICAL ISSUES D-1
NON-TECHNICAL ISSUES D-14
APPENDIX E: AUSTRALIAN DEVELOPMENTS AND EUROPEAN EXPERIENCE E-1
DEVELOPMENTS IN AUSTRALIA E-1
EXPERIENCE IN THE NETHERLANDS E-1
Notes on Two Dutch Landfill Gas Workshops E-11
Commercial Use of Carbon Dioxide: By-product of Landfill Gas Purification E-12
EXPERIENCE IN THE UNITED KINGDOM E-13
Quality Assurance and Risk Management E-15
Gas Utilization Technology E-35
APPENDIX F: MAKING LANDFILL GAS AN ASSET (Paper) F-1
APPENDIX G: LANDFILL GAS RECOVERY SYSTEMS FOR EXISTING LANDFILL SITES
(Presentation) G-1
APPENDIX H: SELECTING ELECTRICAL GENERATING EQUIPMENT FOR USE WITH
LANDFILL GAS (Paper) H-1
APPENDIX I: GAS CONDITIONING KEY TO SUCCESS IN TURBINE COMBUSTION SYSTEMS
USING LANDFILL GAS FUELS (Paper) 1-1
APPENDIX J: COMPRESSED LANDFILL GAS AS A CLEAN, ALTERNATIVE VEHICLE FUEL
(Paper) J-1
APPENDIX K: THREE EPA MEMORANDA ON NEW SOURCE REVIEW RELATING TO
LANDFILLS AND LANDFILL GAS K-1
APPENDIX L: ALTERNATIVE ENERGY & REGULATORY POLICY: TILL DEATH DO WE PART
(Presentation) L-1
APPENDIX M: RECENT DEVELOPMENTS, FUTURE PROSPECTS FOR SALES OF ELECTRICITY
FROM FACILITIES WHICH BURN LANDFILL GAS (Presentation) M-1
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TABLES
1. LANDFILL GAS ENERGY APPLICATIONS IN THE UNITED STATES 1
2. COMPARISON OF NATURAL AND LANDFILL GAS 9
3. SOME TECHNICAL ISSUES, EFFECTS, AND POSSIBLE REMEDIES . . ; 13
4. GAS PURIFICATION METHODS AND PRINCIPLES 42
FIGURES
1. Landfill gas recovery sites in the United States 4
2. Number of projects per State 5
3. Net electrical output in MW per State per type of generating equipment 5
4. Number of projects per end use per year 6
5. Number of 1C engine projects (including gas turbines) per year per manufacturer 7
6. Net electrical output in MW per year per type of generating equipment 8
7. Net electrical output in MW per year per developer 8
8. Simplified landfill gas flowchart for 1C engines (limited cleanup) 21
9. Simplified landfill gas flowchart for 1C engines (stringent cleanup) 23
10. Simplified landfill gas flowchart for gas turbines (example 1) . 25
11. Simplified landfill gas flowchart for gas turbines (example 2) 26
12. Chart to calculate production tax credits from landfill gas flow 39
13. Chart to calculate electricity output from landfill gas flow 40
14. Fuel cell 45
15. Chemical reactions in a phosphoric acid fuel cell 45
E-1. Energy from landfill gas in the United Kingdom E-14
E-2. Simplified Process & Instrumentation Diagram for Typical Landfill Gas Abstraction and
Utilization System E-34
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ACKNOWLEDGEMENTS
The authors gratefully acknowledge the advice and assistance of the many contributors to this report.
Special thanks goes out to Susan Thorneloe of U.S. EPA's Air and Energy Engineering Research
Laboratory, Research Triangle Park, North Carolina. Susan is a strong advocate of landfill gas utilization,
because she believes in its benefits to the environment. She also has been clearly aware of the need for
information transfer to encourage landfill gas utilization and to broaden the understanding of its implications
among users, developers, and regulators alike. She was able to conceptualize this need and encourage
the materialization of this document, by ensuring the participation of many landfill gas experts. We would
like to acknowledge these landfill gas experts here and have listed them below in alphabetical order:
Charles Anderson, RUST Environment, Naperville, Illinois
Robert Anuskiewicz, Solar Turbines, Inc., San Diego, California
David Byrnes, San Diego Air Pollution Control District, San Diego, California
Curt Chadwick, Caterpillar, Mossville, Illinois
Philip Coerner, Cleaver-Brooks, Milwaukee, Wisconsin
Gordon Deane, Palmer Capital Corporation, Cohasset, Massachusetts
Stanley Drake, Energy Tactics, Inc., Yaphank, New York
Richard Echols, Browning-Ferris Industries, North Eldridge, Texas
Frans van Gaalen, Ingenieursburo Innogas, Gorinchem, The Netherlands
Brian Gullett, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina
George Jansen and Matt Nourot, Laidlaw Environmental Services, Newark, California
David Maunder, Energy Technical Support Unit, Harwell, United Kingdom
Ralph Nuerenberg, Granger Renewable Resources, Inc., Lansing, Michigan
Paul Persico, Brian Pell, and Thomas Normoyle, GSF Energy, Allentown, Pennsylvania
Alex Roqueta, Landtec, Commerce, California
Martin Scheepers, Landfill Gas Advisory Center, Utrecht, The Netherlands
Frank Wong, Pacific Energy, Commerce, California
vm
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ABBREVIATIONS
AEERL Air and Energy Engineering Research Laboratory
BACT Best available control technology
CAA Clean Air Act
FERC Federal Energy Regulatory Commission
ETI Energy Tactics, Inc.
EPA Environmental Protection Agency
GC Gas chromatograph
HHV Higher heating value
1C Internal combustion (engine)
LHV Lower heating value
O&M Operation and maintenance
pH Acidity level
PTC Production tax credit
PSA Pressure swing absorption
PUC State Public Utility Commission
SWANA Solid Waste Association of North America (formerly GRCDA)
TBN Total base number
U.K. United Kingdom
U.S. United States of America
WMNA Waste Management of North America
CH4 Methane
CO Carbon monoxide
CO2 Carbon dioxide
H2O Water
H2S Hydrogen sulfide
N2 Nitrogen
NMOCs Nonmethane organic compounds
NOX Nitrogen oxides
PCDD Polychlorinated dibenzo-dioxin
PCDF Polychlorinated dibenzo-furan
PCS Polychlorinated biphenyl
PVC Polyvinyl chloride
VOC Volatile organic compound
Btu British thermal unit
ft Foot or feet
g Gram
kPa Kilopascal
kW Kilowatt
m Meter
MW Megawatt
ppm Parts per million
ppmv Parts per million (volume)
psi Pounds per square inch
psig Pounds per square inch (gage)
scf Standard cubic feet (per minute or per day)
W Watt
IX
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CONVERSIONS
Multiply
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
Pascals
Atmospheres
Pounds per square inch
Pascals
Bar
Inches of water
By
0.3048
0.0254
39.37
3.281
106
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
1.45x10-"
10s
249
To Obtain
Meters
Meters
Inches
Feet
Micrometers (sometimes referred to as 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
Newtons/m2 (1 Newton is the force required to
accelerate 1 kg at 1 m/second2.)
Pascal
Pascal
Pounds per square inch
Pascal
Pascal
(continued)
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CONVERSIONS (continued)
Multiply
By
To Obtain
POWER
Watts
Watts
Watts
ENERGY
Joules
Kilowatt-hours
Kilowatt-hours
Kilowatt-hours
Btus
MISCELLANEOUS
Cubic meters per hectare
Cubic meters per hour
Cubic feet per minute
Cubic feet per Ib per year
Btu/scf
1
0.05692
1.341x10'3
1
3415
1.341
3.60x1 06
1,054
14.291
0.5886
0.02831
61
37,243
Newtonmeter/sec. or joule/sec.
Btus/minute
Horsepower
Wattsecond or Newtonmeter
Btu's
Horsepower-hours
Joules
Joules
Cubic feet per acre
Cubic feet per minute
Cubic meters per minute
Cubic meters per tonne per year
Joules/cubic meter
Temperature conversion:
"Standard" conditions
"Normal" conditions
°C x 1.8 + 32 - °F (Fahrenheit)
(°F-32)/1.8 - °C (Celsius)
60°F and 14.7 psi.
0°C and 1.01325 x 10s pascals
Density of methane = 715.631 g/m3 (at STP: T = 0 °C, P = atmospheric = 101,325 Pa)
METRIC PREFIXES
Name
tera
mega
kilo
hecto
deka
deci
centi
milli
micro
T
G
M
k
h
da
d
c
m
Value
1012
109
106
103
102
10
10'1
10'2
10'3
10'6
XI
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1. INTRODUCTION
1.1 BACKGROUND
Microbial decomposition of refuse buried in sanitary landfills generates landfill gas consisting principally of
55 to 60 percent methane (CH4) and 40 to 45 percent CO2. The gas generation within any given landfill
generally rises to a peak shortly after closure, and then declines at a rate that depends on waste
placement, composition, moisture content, and many other factors (EMCON, 1982; Augenstein and Pacey,
1991). Landfill gas is recovered for energy utilization at 110 sites in the United States (Thorneloe and
Pacey, 1994). Extraction systems typically consist of vertical wells, and sometimes horizontal trenches or
other zones filled with permeable material within the waste, from which gas is extracted by application of
vacuum. The gas is drawn into a piping network by a blower (suction) or compressor and transported to
a flare or, where economics and other circumstances are favorable, to an energy utilization plant. In spite
of relatively unattractive enrgy markets, landfill gas uses are continuing to increase both in the United
States and worldwide. Landfill gas is normally used for fuel in energy equipment that is widely available
commercially, though primarily designed to be fueled by natural gas. The specific energy applications for
which landfill gas is most commonly used are shown in Table 1.
TABLE 1. LANDFILL GAS ENERGY APPLICATIONS IN THE UNITED STATES
Applications
Degree of Use
Number of Projects
Current Applications
Direct Use
Space Heating (and cooling)
Industrial Process Heat
Boiler Fuel
Electrical Generation
Reciprocating Internal Combustion Engines
Gas Turbines
Steam Turbines
Other
Purification to Pipeline Quality
Common
20
Most common
Common
Limited
Limited
60
21
5
Emerging Applications
Electricity Generation using Fuel Cells
Compressed CH4 Vehicle Fuel
"Synfuel" or Chemical Feedstock
Organic Rankine Cycle (heat recuperation)
and Stirling Cycle Engines
One full-scale demonstration project in 1994/1995
sponsored by EPA/AEERL.
One pilot-scale demonstration project (see
Appendix J).
One full-scale project under construction
None
Source: Thorneloe and Pacey, 1994.
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Landfill gas is substantially different from natural gas. Natural gas, often referred to as pipeline gas, is
typically supplied from a high pressure transmission line as a clean, dry gas. It is delivered to the energy
conversion equipment at constant temperature and pressure and at a constant flow, with a constant energy
content. The energy conversion equipment available for use of landfill gas is normally designed to use
natural gas, although several manufacturers are now marketing modified equipment. However, landfill gas
reaches the energy conversion facility in a dirty and wet state. Its pressure is very low and its temperature
may vary from well below ambient to 60°C (140°F). The moisture contained in landfill gas is acidic and
corrosive. Also entrained in the gas is particulate matter derived from refuse and daily cover material (e.g.,
soil) as the gas is drawn into the piping vacuum. Landfill gas delivered to the facility varies in quantity and
energy content on a daily and seasonal basis. All of these conditions and characteristics of landfill gas raise
issues not associated with pipeline gas usage. The distinctive attributes of landfill gas, and their
consequences to energy use, are reviewed in this report.
1.2 PURPOSE OF THIS REPORT
This report is a follow on to an earlier EPA report entitled: "Landfill Gas Energy Utilization: Technology
Options and Case Studies" (Augenstein and Pacey, 1992). The purpose of this earlier report is to provide
general information on landfill gas energy uses. It also includes information on landfill gas generation,
modeling, or field development. Case studies document the experience at representative U.S. sites where
landfill gas has been used for its energy potential. The Abstract and the Table of Contents of "Landfill Gas
Energy Utilization: Technology Options and Case Studies" are included in Appendix A. Also, other
suggestions for further reading are included in Appendix B of the current report.
The current report may serve as a tool to help potential developers of landfill gas energy conversion projects
select between options. Information in the current report was gathered during extensive interviews with
private developers and operators of landfill gas energy conversion projects. (Summaries of these interviews
are included in Appendix D.) The report addresses the technical, as well as the non-technical considerations
involved with landfill gas utilization and it relates possible resolutions to these issues as they are applied
by different operators, Design, as well as operation and maintenance considerations, are taken into account.
Non-technical considerations include, but are not limited, to the following: 1) selection of energy utilization
options; 2) project economics (financing, return on investment, profit, cost/benefit, etc.); 3) potential barriers
(taxation, regulations, communication with Agencies and Commissions); and 4) incentives.
It is hoped that the information on non-technical barriers will contribute to a better understanding of the
perspective of private developers/operators among all parties involved with landfill gas utilization. Apart from
developers and operators, these parties include but are not limited to: public and private landfill owners;
local, state and federal regulators concerned with solid waste, water quality, air quality, and global warming
issues; financial institutions; utilities; and end users. Landfill gas energy conversion can benefit if all above
parties are aware of each others viewpoints and objectives and participate in fruitful communication. This
document is not intended to provide a comprehensive overview of the many different perspectives of all
parties involved. Instead, it summarizes the experience of current private developers and operators in an
effort to provide information to the public and more in particular, to assist future developers and operators
in developing landfill gas utilization projects as a compliance option for potential CAA regulations for landfill
air emissions. Consequently, this document will present the issues from the industry's perspective and it
will not necessarily reflect the views of the authors, nor of the U.S.EPA.
A data base of landfill gas to energy projects in the United States is being developed on both technical and
non-technical issues. This will help to document the extent that the issues identified by the major developers
and operators are affecting new and existing projects (Thorneloe and Pacey, 1994). Additional information
on technical problems encountered at 11 landfill gas utilization sites in the United Kingdom (U.K.) is available
and has been included in Tables D1 and D3 of Appendix E. Appendix E presents landfill gas experiences
in two European countries; the Netherlands and the U.K. and gives a brief overview of developments in
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Australia. Also, a project to research utilization of landfill carbon dioxide (CO2) in the Netherlands is
summarized.
Facing new requirements for controlling landfill gas, many landfill owners are eager to turn the liability of the
gas into an asset. Options to do so are discussed in Appendix F. The next appendix gives a step by step
account on furnishing an existing landfill site with a landfill gas recovery system. In Appendix H, the
attributes of various proven technologies for generating electricity while utilizing landfill gas as a fuel are
discussed. Equipment size, installation and operating costs, air emissions, and plant efficiency are
compared.
Appendix I contains a paper that presents a detailed account on the use of landfill gas turbines, including
a failure analysis, resulting in re-evaluation of the process design. In Appendix J, an account is given of
the utilization of landfill gas as vehicle fuel, one of several emerging technologies, which are detailed in
section 4 of the report. An EPA memo dated July 1994 providing the EPA's New Source Review policy
which regards landfill gas to energy projects as potential pollution prevention sources is included in Appendix
K. Appendices L and M focus on non-technical issues such as the sale of electricity from landfill gas
projects and alternative energy regulatory policies.
1.3 DEVELOPMENT OF THE LANDFILL GAS INDUSTRY AND TRENDS
Numerical data used in this section originate from a data base developed by AEERL and Solid Waste
Association of North America (SWANA) (Thorneloe and Pacey, 1994). This data base is being updated and
is to be published in an EPA report in spring 1995. Copies may then be obtained through EPA's Control
Technology Center [hotline: (919) 541-0800], SWANA, or the National Technical Information Service (NTIS).
The landfill gas industry is almost 20 years old. The first commercial landfill gas energy conversion project
was placed on line at Palos Verdes Landfill, Rolling Hills, California in 1975. It converted landfill gas to
pipeline quality gas that was sold to the Southern California Gas Company. Several additional landfill gas
to pipeline quality projects were brought on-line in the late 1970s, including Mountain View (1978) and
Monterey Park (1979), both in California. Direct firing boiler projects were brought on-line in the late 1970s
and early 1980s. The first landfill gas-to-electricity project occurred at Brattleboro, Vermont in the latter part
of 1982, and electrical projects have dominated ever since. Currently, there are 110 landfill gas utilization
projects in the United States. Most projects are in California and in the Northeast (Figures 1 and 2).
In general, many of the interviewed developers and operators of landfill gas to energy projects in the United
States assert that more incentives are needed to overcome the low revenues resulting from these projects
primarily due to the relatively low cost of fossil fuel. Those interviewed suggested that over the last decade,
energy prices have neither been adequate nor sufficiently stable to fully support landfill gas projects.
California has created such an incentive: a price favored contract that utilities must offer known as Standard
Offer #4 (SO4). This offer encouraged numerous landfill gas-to-electricity projects in California in 1984 and
1985. The last project under SO4 was started in 1990. Several of these offers have run out and some
projects have had to close down when the pricing structure was reverted to the avoided cost price basis (of
the utility). New Jersey, New York, and Pennsylvania adopted a Pioneer Floor Rate of $0.06 per kilowatt-
hour (kWh) in the mid-1980s, however this was cancelled again several years ago. Illinois, Michigan, and
Wisconsin have offered energy price incentives to limited landfill gas projects, thereby encouraging modest
project development (Figures 1, 2, and 3).
Figure 3 gives an overview of the net electrical output from landfill gas projects per State per type of
generating equipment. California produces 35 percent of all landfill gas generated electricity. New York,
Pennsylvania, Michigan, Illinois, and Wisconsin produce an additional 35 percent, raising the percentage
of net output contributed by the six states to 71 percent. Landfills in these states are required to collect and
control the landfill gas. Incentives in these states may have contributed to increased landfill gas utilization
over flaring.
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Figure 1. Landfill gas recovery sites in the United States.
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California
New York
Michigan
Pennsylvania
Illinois
Wisconsin
New Jersey
Man/land
North Carolina
Texas
Oregon
Ohio
New Hampshire
All Others
10
15
20
25
30
35
40
Figure 2. Number of projects per State.
CALIFORNIA
NEW YORK
MICHIGAN
ILLINOIS
WISCONSIN
PENNSYLVANIA
FLORIDA
RHODE ISLAND
NEW JERSEY
VIRGINIA
MARYLAND
OTHERS
Steam Turbine
D Gas Turbine
C3 Reciprocating Engine
40
60 80
MW (net)
100
120
140
Figure 3. Net electrical output in MW per State per type of generating equipment.
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Historically, through the 1980's a developer who wished to undertake a landfill gas to energy project
compensated the landfill owner for the rights to the landfill gas. In addition, the developer paid all cost
associated with the extraction system, and taxes, where applicable. The current situation is that the energy
prices are at a very low level and those interviewed assert that barriers of many types have been
established. However, several new incentive programs have recently been established under President
Clinton's Climate Change Action Plan, which may directly affect the CH4-from-waste industry. The
Department of Energy is implementing a research, development, and demonstration program targeted at
the technical barriers to landfill CH4 energy recovery. Another component of the Climate Change Action
Plan is the Landfill Methane Outreach Program of the EPA. Both incentives are discussed in section 5.4.
Generally, a direct firing project (i.e., boiler or kiln), immediately adjacent to the landfill is the most cost
effective type of project. However, there are not always boilers in close proximity to landfills and with
continuous fuel demands (i.e., 24 hours a day, 7 days a week). Consequently there are only 20 boiler
projects that have been developed in the United States (Figure 4). Also, larger landfills produce quantities
of gas that require several nearby gas customers requiring continuous demand for fuel in order for all the
gas to be utilized. This is not always possible. In addition, projects that purify landfill gas to pipeline quality
gas have not always been economically viable over the past decade. GSF Energy, Inc. is the only current
developer in this area. However, over the past decade there has been significant growth in the use of
reciprocating internal combustion (1C) engines, in landfill gas applications (Figure 4). Reciprocating 1C
engines are efficient and have reached a high degree of standardization, encouraging modular availability.
It is now possible to employ skid-mounted engines that can be easily moved onto site or to another site,
should changes in landfill gas availability make this necessary.
120
100
80
60
82 83 84 85 86 87
40
D Reciprocating Engine
EG as Turbine
D Boiler
D Steam Turbine
Pipeline Quality
88 89 90 91
Figure 4. Number of projects per end use per year.
92 93
It has been estimated that CAA regulations under consideration for new and existing municipal solid waste
landfills may require up to 700 medium- and larger-sized sites to install and maintain a landfill gas
extraction and control facility. These rules are scheduled for promulgation in June 1995. If economics are
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favorable for landfill gas energy conversion projects as compared to flaring, it would appear that 1C engines
will continue to be favored. Those interviewed beleive that the growth of other types of landfill gas energy
conversion options will depend strongly on the reduction of barriers and availability of incentives. The trend
in municipal solid waste management toward larger regional landfills may help encourage the development
of landfill gas to energy projects. Landfill owners will be looking for options to minimize potential control
costs and converting the landfill gas to energy provides an opportunity to comply with the regulations and
generate revenue. (Doom et al. 1994).
The growth of the various engine and turbine projects is illustrated in Figure 5. Since 1989, Caterpillar has
had the most growth. In that year, Caterpillar in cooperation with Waste Management of North America
(WMNA) produced a "low pressure" 1C engine system that has eliminated the need for an auxilary high
pressure compressor. This reduced contaminant emissions and parasitic loading. Waukesha and Cooper-
Superior have now also introduced 1C engines with low pressure capability.
H Caterpillar
• Waukesha
Cooper-Superior
D Other R 1C
H Gas Turbine
82 83 84 85 86 87 88 89 90 91 92 93
Figure 5. Number of 1C engine projects (including gas turbines) per year per manufacturer.
The growing importance of 1C engines is again reflected in Figure 6. The total net electrical output from
the landfill gas industry is now over 300 MW, with 1C engines accounting for 143 MW. This output is
generated from 60 projects (Figure 4), resulting in an output per 1C project of 2.4 MW. For gas turbines
and steam turbines this number is higher; 4.8 and 13.8 MW/project, respectively. Although 1C engine
projects are favored in the lower MW range, some larger 1C projects are also compatible.
The most aggressive developer in terms of MW output growth over the past few years has been WMNA
(Figure 7). Other solid waste management firms with landfill gas interests include Laidlaw and BFI. BFI's
expansion is principally limited to their own landfills. Developers, such as Energy Tactics Inc., Granger,
Laidlaw, and Landfill Energy Systems aggressively market individual landfill owners.
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D Reciprocating Engine
D Gas Turbine
H Steam Turbine
82 83 84 85 86 87 88 89 90 91 92 93
Figure 6. Net electrical output in MW per year per type of generating equipment.
UWMNA
DLACSD
DPEN
EJLAIDLAW
• ETI
D All Others
82 83
Figure 7. Net electrical output in MW per year per developer.
8
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2. LANDFILL GAS PROPERTIES
2.1 COMPOSITION AND CONTAMINANTS
This section describes the properties of landfill gas which may cause technical problems in landfill gas
equipment. The properties discussed include landfill gas composition and contaminants, flow
characteristics, and energy content. Except where noted, the information discussed in this section was
obtained from interviews with owners and operators of landfill gas utilization schemes. Summary texts of
these interviews are included in Appendix D.
Characteristic composition ranges for landfill gas (as it is delivered to the energy conversion facility) are
shown in Table 2. Natural gas characteristics are included for comparison. As noted earlier, landfill gas
contains methane, CO2, and smaller quantities of nitrogen, trace gases, and water vapor. These
constituents dilute the gas, reducing its energy content per unit volume compared to natural gas. Landfill
gas contains trace gases of NMOCs and significant quantities of solid paniculate matter, especially right
after startup.
TABLE 2. COMPARISON OF NATURAL AND LANDFILL GAS
Component
Methane (CH4), (%)
Ethane + Propane, (%)
Water (H2O) vapor, (%)
Carbon dioxide (CO2), (%)
Nitrogen (Nz), and other inerts, (%)
Trace condensible hydrocarbons (NMOCs) (ppmv as
Natural Gas
(as extracted)
90-99
1-5
<0.01
0-5
0-2
-0-
Landfill Gas
40-60
-0-
1-10
35-50
1-20
250-3000
hexane)
Chlorine in organic compounds (ug/l) -0- 30-300
Hydrogen Sulfide (H2S) (ppm) up to 15 5-50
Higher heating value, Btu/ft3 950-1050 400-600
Sources: Gas Engineers Handbook, 1965; Vogt and Briggs, 1989; EMCON et al., 1981.
Units are those most commonly used for the stated component.
Nonmethane organic compounds include a wide range of organic compounds, mostly from volatile materials
thrown away in refuse (e.g., vapors from oily rags and paint solvents). Since they burn up along with the
methane, most NMOCs are not considered harmful if used in landfill gas energy conversion processes.
A few, however, present concerns with particular applications. The greatest potential problems are posed
by halocarbons [the chlorinated and fluorinated (halogenated) hydrocarbons]. These include the
chlorofluorocarbons widely used in the past in refrigeration equipment and as aerosol propellants, and other
solvents such as dry cleaning fluids. Though many of these are being phased out for environmental
-------
reasons, they are still found in landfill gas as old aerosol containers (and other items containing these
substances) corrode and the contents find their way into the gas.
The problem with halocarbons is that they combust to products that include hydrogen chloride gas and (to
a lesser extent) hydrogen fluoride gas. Although their concentrations may be low, the gases are readily
reactive with, for example, metal in internal combustion (1C) engines and gas turbines.1 Other NMOCs can
present similar problems. Organic acid components in aqueous phase can also corrode carbon steel.
As listed in Table 2, untreated landfill gas is at most 60 percent methane, with the balance being inert
gases, principally CO2; it has lower energy content than the natural gas on which most energy equipment
would normally operate. Therefore, one consequent requirement is that the energy system, including
valves, pipes, and fuel metering, must introduce about twice the gas volume, relative to incoming air, as
is required with natural gas. This can be achieved by modifications that are relatively straightforward, for
example, by both increasing the number of burner orifices and/or enlarging them (in boilers), or modifying
fuel/air ratio (in 1C engines and gas turbines).
2.1.1 Condensate
"Condensate" may form as a result of decreasing gas temperature and/or increasing pressure. Condensate
is a dilute solution (one to a few percent) of the condensed water and contaminants found in landfill gas.
Large quantities of condensate may be generated in the field when warm [>38°C (>100°F)] gas, saturated
with water vapor, exits a landfill and cools to ambient temperature. Condensate generated in the field
collection lines must be drained or it can block them. Even with appropriate field collection system
drainage, some condensate will typically reach the plant; it may arrive slowly and steadily over time, flowing
with or entrained in the gas. Large quantities of condensate in the system (termed "slugs" by some
operators) may also mobilize and arrive all at once. Slugs must be removed before the gas enters the
blower or compressor units. Further condensate can also result within the plant, due to cooling or
refrigeration following gas compression.
2.1.2 Deposits
Landfills contain soil and other particulate matter that can be drawn into the landfill gas stream where it can
pose various problems with energy generating equipment. The specific problems actually seen include
deposits in 1C engines, including gas turbines, and buildups in the oil of 1C engines such that oil life is
shortened and engine wear is increased. Particulate matter can be removed by gas filtration. When landfill
gas pretreatment is by filtration alone, without refrigeration/gas drying, deposits may slowly build up in 1C
engine cylinders or in gas turbines. These deposits have been found to contain silica and alumina, with
lesser fractions of other solid compounds. Filtration is generally considered to be highly effective, so these
deposits must have another origin than from particles in the gas stream. An explanation may be found in
the existence of a gaseous compound in landfill gas, containing silicon: dimethyl siloxane [(CH3 )2SiO].
This compound will combust to give silica as a product, which could explain the presence of silica in these
engine deposits, as well as in the engine oil.
Field experience proves that dimethyl siloxane deposits are effectively averted by gas refrigeration. This
is quite peculiar, since this compound is low-boiling, implying that it is gaseous at all times. Mechanisms
1 Internal combustion engines burn fuel on the inside; the expanding gases provide the kinetic energy (shaft
power). External combustion engines burn fuel on the outside. The fuel merely serves as a heat source to heat,
for instance steam. Then the steam provides the kinetic energy. Therefore, stricktly speaking, a gas turbine is also
an 1C engine. The term reciprocating internal combustion engine is sometimes used to indicate that the engine has
pistons. '
10
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that allow for its removal are not fully understood. Also, no gaseous or soluble compound has been found
in landfill gas that might be a carrier of the aluminum/alumina found in deposits. So, if it is assumed that
filtration is working as it appears to be, the presence of alumina, and for that matter other solid
components, (other than oil base ash) is unexplained.
2.1.3 Other Potential Issues
Polychlorinated dibenzo-dioxins (PCDD) and dibenzo-furans (PCDF) are highly toxic compounds that have
been associated with the combustion of chlorine-bearing waste. The preponderance of current thinking is
that dioxins and furans can be destroyed with combustion, but that reformation of PCDD and PCDF can
occur in the post-combustion phase if certain conditions exist: temperatures ranging from about 700 to
1,000°F (370 to 540°C); particulate matter containing copper, iron, or aluminum, or even carbon, which
serves as a catalyst; and adequate retention time for the reformation to develop.2 (Gullett et al., 1994).
The issue of PCDDs and PCDFs in landfill gas emissions has been raised on a few instances. It is
important to recognize that landfill gas combustors, whether they be flares, internal combustion engines,
gas or steam turbines, differ significantly from incinerators, or waste combustors. First of all, landfill gas
combustors do not burn solids, such as PVC or other plastics as do incinerators. In addition, landfill gas
is usually subject to filtration prior to combustion in a landfill gas energy utilization project, which would
remove catalytic particulates. Also, temperatures conducive to PCDD/PCDF formation occur in a very short
time interval. This is because the exhaust from the landfill gas control or energy utilization project is rapidly
quenched as it leaves the exhaust region and enters the atmosphere.
Several landfill gas utilization projects have been tested for PCDDs, PCDFs and polychlorinated biphenyls
(PCB) (another hazardous pollutant). Test reports exist for two boilers, one flare, and one gas turbine
(Kleinfelder, Inc., 1991; Millican, 1994; Moilanen, 1986; and Pape & Steiner, 1990). For the flare, the gas
turbine, and one of the boilers the emission results were all less than the detection limits for all of the above
combustion products. However, from a health risk standpoint, the detection limits were probably set too
high. For instance, the boiler emission rate detection limits were as high as 4.3 X 10"" Ib/hr, whereas rates
necessary to protect public health may need to be as low as 10"7 Ib/hr. The positive test results of the
remaining boiler were below the 10'7 Ib/hr limits, however one of the laboratory blanks also tested positive.
Therefore, results from this test are also considered inconclusive. Current thinking is that the combustion
of landfill gas will not be a major source of PCDDs/PCDFs as compared to those processes that favor
dioxin and/or furan formation (e.g., municipal waste combustion).
2.2 VARIABLE FLOW AND ENERGY CONTENT
Landfill gas flow (rate, as well as volume) is determined by many factors. First, landfill gas flow is directly
related to the gas generation rate. Generation rates change over time and depend on the biological
processes occurring within the landfill. Typically, landfill gas generation should peak a few years after
landfill (or section) closure, and then gradually decrease over a period that may last decades. Secondly,
flow depends on meteorological factors, such as temperature and barometric pressure changes that cause
the gas to expand or contract. Lastly, flow depends on the performance and efficiency of the extraction
system. Landfill gas is drawn to the energy conversion equipment by a vacuum. Leaks in the equipment
or pipes will result in air intrusion that will dilute the gas. This dilution will effectively decrease the energy
content of the gas (also, air intrusion might create an explosion hazard). Pressure considerations are
discussed further in the next section.
2 Gullett, Brian. 1994. U.S.EPA/AEERL. Personal communication with John Pacey of FHC, Inc. and Susan
Thorneloe of U.S. EPA, AEERL, Research Triangle Park, NC. June 14, 1994.
11
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Gas energy content must be known and monitored so that fuel metering (e.g., air/fuel ratio) can be
adjusted. Also, energy content measurements may be necessary for accounting purposes. In certain
cases, it will suffice to determine the calorific value of the landfill gas. Gas composition measurements may
be made by methods based on principles of thermal conductivity, infrared absorption, or gas
chromatography. Flow measurements may be made using a pilot tube, orifice plate, turbine flowmeter, or
other equipment. The figure on page E-34 in Appendix E provides a simplified process and instrumentation
diagram for a typical landfill gas clean-up system. Generic issues regarding instrumentation and sampling
are discussed in "Landfill Gas Utilization: Technology Options and Case Studies" (Augenstein and Pacey,
1992).
Because landfill gas supply may be insufficient for the installed capacity, a few operations supplement
landfill gas with natural gas. One method for supplementing is to blend natural gas with landfill gas. This
blending requires fairly close attention and control. Another method applicable to all equipment, but most
readily to direct combustion equipment (i.e., boilers), is to provide dedicated separate and independent
burners for each of the alternative fuels desired. This can eliminate control problems and allow simple
switchovers between landfill gas and the other alternative fuels. One manufacturer of 1C engines
recommends to switch an engine entirely to natural gas, in case landfill gas supply is temporarily low, thus
avoiding most control readjustments.
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3. TECHNICAL ISSUES, SOLUTIONS, AND FIELD EXPERIENCE
3.1 GENERAL
This section provides a discussion of the technical issues raised in the interveiws associated with the use
of landfill gas compared to natural gas—which is the primary fuel used for energy conversion equipment
such as reciprocating engines, gas turbines, and fuel cells. Technical issues (Table 3) arise as a result of
the relatively low heating value or from the presence of chlorinated and toxic compounds, particulates, as
well as the formation of condensates or deposits. [For landfill gas the heating value is approximately
19x106 Joule/m3 and for natural gas it is approximately 37 Joule/m3 (500 vs. 1,000 Btu/scf).] This section
reviews these technical issues and summarizes current field experience in minimizing various adverse
effects.
TABLE 3. SOME TECHNICAL ISSUES, EFFECTS, AND POSSIBLE REMEDIES
System Part
Effect
Remedy
CORROSIVE GAS
General
All Metal
Compressors
1C engines
Corrosion
Corroded valve parts may
enter
Condensate management
Avoid carbon steel
Modification to valve assembly and/or frequent
replacement of parts
Use of oils and lubricants with high total base
number
CONDENSATE
Line blockage/
Slugs
Disposal problem
Condensate traps and drains and/or
Temperature management and/or
Removal of contaminants with solvents
VARIABLE GAS FLOW
General
Poor performance due to
variable flow and quality
Extraction system management
LOW HEAT VALUE (compared to natural aasl
Engines
Boilers
Lower combustion
temperature
Slower flame front
propagation
Adjust fuel/air ratio
Adjust burner
13
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To obtain pragmatic and recent information, interviews were conducted with five developers and/or
operators of landfill gas energy projects and one engine manufacturer, including:
• BFI; solid waste management firm with 5 in-house landfill gas utilization projects,
• Laidlaw; large developer and operator of turn-key projects,
• Pacific Energy; mid-sized operator,
• GSF Energy/Air Products; landfill gas purification to pipeline quality,
• Rust Environment and Infrastructure/Waste Management of North America (WMNA); large
developer and operator,
• Caterpillar; gas engine manufacturer.
Write-ups of the interviews are included in Appendix D. More information on technical issues associated with
landfill gas utilization can be found in the appendices to this report. Appendix E includes a section from a
British document, entitled: "Gas Utilization Technology." This write-up contains comprehensive tables of
operating details of U.K. landfill gas utilization projects.
3.1.1 Pressure Considerations
In contrast to natural gas, landfill gas needs to be pumped to the point of use. Extraction of landfill gas
typically requires a blower designed to pump large volumes of gas at low pressure drops. A blower may
maintain a header vacuum (at the blower inlet) of 20 to 80 inches of water column [5 to 20 kilopascal (kPa)]
and will discharge to processing and energy equipment at pressures between 1 to 10 pounds per square inch
(psi) (7 to 70 kPa). Certain pretreatment 1C engines and gas turbines require higher fuel pressures typically
ranging from 240 to 1,030 kPa (35 to 150 psi). A high pressure compressor may be combined with a low
pressure blower, or the compressor may serve alone for both field extraction and fuel delivery.
The gas enters the blower or compressor before most of the cleanup is accomplished and, thus, contamination
(which can result in corrosion) is a concern. Standard blowers and compressors are normally designed for
dry gas service only, and liquid condensate would damage them. Blowers for the landfill gas industry use
impellers and housings that are either coated or made entirely of plastic. Compressors are made of modular
iron or cast iron. No significant corrosion has been reported regarding landfill gas blower or compressor
usage. Also, blowers are said to resist damage from condensate slugs reasonably well. According to
operators, blowers are among the most reliable equipment items at landfill gas energy facilities. Down time
is estimated to be 1 percent or less between normal blower service intervals.
In general, compressors also seem to be reliable when certain precautions are taken. Estimates indicate that
the down time due to malfunctions is around 1 percent (precise statistics were not obtained). Compared to
blowers, the compressors are more susceptible to contaminants and condensate slugs, making condensate
removal and maintenance critical to their reliability. With some compressor types, breakdowns of valve
assemblies have led to various parts being sucked into the compressors, thereby creating serious problems.
Operators have been able to avoid this problem through custom modifications of valve assemblies so that
corroded valve assemblies stay together. Also, frequent replacement of susceptible parts has proven to be
beneficial.
3.1.2 Material Modifications
With landfill gas, certain changes of materials may be required to avoid corrosion caused by water and
various organic and particulate matter components in the gas or condensate.
For gas pretreatment, one simple rule is to avoid carbon steel where an aqueous phase might occur.
Carbon steel is readily corroded by compounds such as organic acids in condensate. When used in low
pressure situations, carbon steel may be coated with corrosion-resistant plastic. For higher pressure
14
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applications, zinc- or epoxy-coated carbon steel or stainless steel may be used. For low pressure piping,
plastics such as polyvinyl chloride (PVC) and polyethylene, among others, are used extensively (Held and
Woodfill, 1989). When using plastic pipes and other components, three characteristics must be considered.
Glue in PVC pipes is susceptible to deterioration resulting from volatile organic compounds (VOC) in the
gas. Also, plastic has a high expansion coefficient, and also, certain types of plastics are susceptible to
UV deterioration. One way to significantly reduce the influence of both characteristics is to bury the pipes,
which is done commonly in Europe, but not in the United States.
For energy conversion equipment, material adaptations are most prevalent with 1C engines. In contrast to
conventional fuels, the largest problem that landfill gas poses is from corrosive compounds in exhaust gas,
and particulates and materials that form deposits (when cleaning is not thorough). The parts of engines
most frequently susceptible to corrosion or wear are exhaust valves, and valve guides and stems. In many
cases these are now chrome-plated. Piston rings have sometimes been hardened. Other material
modifications may be made. The information on other material modifications is limited (proprietary);
however, based on reports from operators and manufacturers surveyed for this document, modifications
do not appear to be extensive and are currently custom built into standard engine models.
Turbine and boiler manufacturers indicate that typically no significant material modifications are made to
the "standard" design for conventional fuels applications (mainly natural gas).3 Also, as a general
observation concerning all energy conversion equipment, there are typically no materials modifications
reported in exhaust systems. Special attention must be given to hot water and steam boilers with
economizers (heat recuperation), where the flue gases are cooled below their dewpoint.
Some sites may use pipelines to transmit landfill gas from the landfill to an energy utilization operation
some distance away. Maximum pressure at the pipeline inlet is normally the boost pressure (line drop) plus
the pressure of intended use. As maximum pressure is normally under 700 kPa (100 psi), pipelines may
be made of either carbon steel (which is relatively inexpensive) or polyethylene. Carbon steel is susceptible
to corrosion from dissolved components in any condensate which might form so, if it is used, condensate
must be prevented. Alternatively, with polyethylene pipe and where cleanliness is not an issue, condensate
traps may be used. A case study of each type of transmission was presented in "Landfill Gas Energy
Utilization: Technology Options and Case Studies." No problems have been reported for either case.
3.1.3 Condensate Management
Condensate will be generated wherever water-saturated gas cools, both within the extraction piping and
the energy facility. Condensate presents several potential problems, which will be discussed below.
Condensate can block lines, reducing gas supply and energy output. Condensate slugs can damage
processing and energy equipment, notably compressors, 1C engines, and turbines. With engines, evidence
suggests its entry may produce deposits (likely resulting from entrained solids). Evidence also suggests
a shortened oil life and accelerated wear in 1C engines, which may be due not only to deposits but also
to the corrosive nature of condensate.
Condensate within the field piping system is ordinarily recovered using condensate traps or drains
strategically placed at piping low points throughout the gas field. Field gas pipes and headers are sloped
to allow drainage and may be resloped periodically to compensate for subsidence. Condensate traps may
be of various designs, some of which are very briefly described in EMCON (1982) and California Integrated
Waste Management Board (1989). Although the field traps will reduce the potential amount of condensate
reaching the plant, their purpose is limited to keeping the extraction system free of condensate blockage
3 Personal communications, Robert Anuskiewicz, Solar Turbines, Inc., San Diego, California, and personal
communication, Philip Coerner, Cleaver-Brooks, Milwaukee, Wisconsin. August 1992.
15
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and slugs. To reduce condensate further, a large condensate interceptor ("knockout") tank is usually placed
directly ahead of the blower or compressor. Knockout tank sizes may be 3,800 liters (I) (1,000 gallons) or
larger. Because of the large cross section, gas velocity is significantly reduced and condensate drops out
and accumulates at the bottom of the tank. Tanks may be baffled; in most cases, the upper reaches of
the tank will contain packing, mesh, or "demister" filters that remove smaller liquid droplets from the gas
leaving the tank. The liquid collected by the mesh or packing also drops to the bottom of the tank.
Both compression (with aftercooling) and refrigeration can generate large amounts of condensate as the
gas loses its capacity to hold water and other condensibles (which is the intention of refrigeration). Proper
design will assure that any liquid condensing prior to contact with the energy equipment can gravity-drain
to an appropriate collection/storage/removal unit. This drainage is particularly important in winter, since
condensate can freeze. Another approach to condensate management is to avoid its formation. For
instance, after passage through the knockout tank the gas may be reheated to avoid further condensation
in the gas feed lines prior to the engines. This may be done in an air exchanger where heat from the gas
leaving the blower is absorbed.
Because of its NMOC content, condensate may present a disposal problem as it is becoming less
acceptable to dispose of it in sewers. Other options, such as on-site treatment are now frequently being
required. Costs are particularly high if the condensate must be disposed of as hazardous waste (which will
depend very strongly on local code). In such cases, condensate handling costs can be high enough to
preclude energy use. Condensate disposal costs may outweigh the gain from improved equipment life.
Readers may consult Vogt and Briggs (1989) or Maxwell (1989), and Augenstein and Pacey (1992) for
further discussion of condensate management.
— Cooling, Refrigeration, and Drying
Refrigerating the incoming gas stream and removing the resulting condensate can result in some benefits
(e.g., reduced engine deposits, increased oil life, and reported reductions of other problems), to be
discussed below in more detail.
When refrigerated, the gas stream is usually cooled to between 1°C and 4°C [34°F and 40°F (the lower
temperature limit is set by the icing that occurs on heat exchanger surfaces)]. At these temperatures most
of the moisture and a fraction of other condensible compounds will drop out. The gas is first compressed
and then refrigerated, which results in the optimum removal of condensibles. Refrigeration is most widely
applied with 1C engines which appear to be the energy equipment most susceptible to contaminants.
Although refrigeration removes many contaminants, there are also some that are not effectively removed.
These include the lower-boiling chlorofluorocarbons (Freons™), whose combustion by-products contain
potentially damaging acid gas compounds.
More water vapor may need to be removed than can be accomplished by refrigeration (e.g., when landfill
gas is piped in cold climates to users some distance from the landfill). Under these circumstances
condensate or ice may form in the pipe, which would not be tolerable. A chemical desiccant, for instance
glycol or silica, may be used in such cases to remove moisture to reduce dewpoints to -17°C (0°F) or
below.
— Rigorous Cleanup Methods
As noted in the section above, refrigeration does not remove all contaminants that could create energy
equipment problems. Several more rigorous cleanup methods may be applied to remove most of these
contaminants. (Other approaches developed for natural gas processing could in principle be applied, but
are seldom used.) The most widely applied "stringent" landfill gas cleanup approach is probably the
Selexol™ process (Shah, 1990 and Hernandez, 1989). In this process, a solvent is used to remove
16
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NMOCs. The solvent can also be chilled to increase removal efficiency. Chilled methanol can be used
similarly to the Selexol™ solvent but, for certain technical reasons, is more appropriate for pipeline
purification than for trace contaminant removal alone. Activated carbon beds can also be used to remove
halocarbons and other organics (Watson, 1990), and can be applied in combination with pressure swing
absorption (PSA) in the purification process for pipeline gas (Koch, 1986).
3.1.4 Aerosol and Paniculate Removal
Some of the smaller liquid droplets that can result from dispersion (or even a "fog" as condensation occurs
in the cooling gas), and smaller particulates, may not be removed by the knockout tanks and its demisters.
Filtration is used to remove such moisture and particles. One type of filter widely used is the coalescing
filter that is designed to remove both entrained liquids and solids. Liquids intercepted by the filter coalesce,
drain from the filter, and are managed with the rest of the condensate. For dry gas, absolute cut-off filters
are often applied; these may be similar to air filters used in automobiles. Filtration is rather straightforward
and several types of filters have been demonstrated to perform well. Some of the filter manufacturers have
been listed in the case studies in Augenstein and Pacey (1992).
3.2 RECIPROCATING INTERNAL COMBUSTION ENGINES
Reciprocating internal combustion engines are most commonly used in landfill gas conversion setups.
Because so many types are in use, they exhibit a high variation in design, degree of gas cleanup, and
operational adaptations. The largest problem that landfill gas poses for 1C engines is from corrosive
compounds in the gas, and particulates and materials that accumulate to form deposits (when cleaning is
less than thorough). The engine parts most frequently susceptible to corrosion or wear are exhaust valves,
and valve guides and stems. As mentioned before, in many cases material modifications are made to
improve performance. Costs for 1C engine plants currently are between $950 to $1,250 per kW.
3.2.1 Oil Selection and Management
In addition to serving as a lubricant, oil can serve to protect interior engine surfaces from corrosion. With
conventional fuels, corrosive compounds stem largely from combustion of the sulfur in the fuel. However,
for landfill gas-fueled 1C engines, the compounds of concern are the halogens that contribute to an acidic
environment. Chemical additives to the oil (called "bases") can largely neutralize these compounds and
reduce corrosion of engine metal.
The index for basic additives in the oil is the total base number (TBN). The acid neutralizing capacity
increases with higher TBN. Landfill gas engines commonly use oils with TBN around 10. However, the
reaction of an acid with a base results in the formation of a "salt," which, if insoluble, will form a deposit.
With the use of higher TBN oils this phenomenon is not uncommon. Deposits in oils are sometimes
referred to as "sulfated" or "oil base ash." A number of other concerns and issues exist with oils, including
buildup of particulate matter and nitration, which occurs when nitrogen oxides (NOX) in product gas reacts
with oil components.
Because of the cardinal role oil plays in landfill gas engines, frequent oil analyses are conducted in which
TBN, nitration, metal content, and various other components are followed to determine when replacement
is warranted. Levels of metals will indicate degree of wear since the previous oil change and could help
to detect engine problems.
The buildup of deleterious volatile compounds in engine oil may be reduced by increasing crankcase
ventilation, which in turn increases the rate at which the compounds are swept by ventilation gas from the
oil. Another route tq reduce buildup of volatiles in the oil is to increase cooling water temperature, hence
17
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block and oil temperature, so that evaporation is maximized and condensation minimized. This will also
facilitate vaporization of water in the oil.
On lubrication of spark ignition engines at the Stewartby site in the U.K., Moss (1991) reports the following:
"Probably the most important item in the care of spark ignition engines, is the monitoring of the
lubrication oil. The process of blending makes it difficult to optimize TEN, ash and extreme
pressure rating. Experience of the different types of oil, particularly in Germany, had shown that
different designs of engines were most suited to different blends of oil. Initially, the oil
manufacturer recommended a CRI 30 which was similar in characteristic to a number of oils used
on the Continent in similar applications. Simple alkalinity tests were undertaken at 100 hour
intervals to assess the remaining basic character of the oil. A full analysis was undertaken every
250 hours which led to oil changes at the 500 hours interval and the 1,000 hours interval. After
this, sufficient experience had been gained to allow the time between oil changes to increase to
1,000 hours intervals with the same full analyses every 250 hours. After running for 5,000 hours,
lacquering was noticed in some of the cylinder bores and on the pistons during routine
maintenance. Also, valve rocker faces and valve stems showed high rates of wear. After
consultation between engine and oil manufacturers, a change in oil specification led to the use of
natural gas 30M oil with increased extreme pressure and TBN characteristics. At the same time
the hardness of the valve seat inserts and valve faces was increased by using stellite surfacing
and the engine water operating temperature was increased from 70°C to 80°C (160°F to 175°F).
At the 10,000 hour interval the effect of the new oil was scrutinized. The greater range in alkalinity
allowed the longer 5,000 and 10,000 hour planned maintenance periods to be extended to 6,000
hours and 12,000 hours, respectively."
Trace quantities of metals in the oil can be an indication of engine wear. In the Stewartby case, there were
elevated levels of both copper and silicon. The main bearings in the engines are made of an aluminum
and tin alloy with phosphor bronze. With no elevated levels of tin in the oil, bearing wear was discounted
and the conclusion was that the copper came from oil cooler tubes. A more extensive search was made
for the source of the silicon. The air filters were modified on one engine, an oil centrifuge was placed on
a second engine, and a bypass filter was placed on a third. Despite these measures, the silicon level
remained high. The problem has not really been resolved. Notable though, is that silicon grease and
silicon rubber O-rings are used in the engines.
3.2.2 Engine Adjustments
On average, landfill gas contains only half as much methane as natural gas. Therefore, it is necessary to
modify the fuel/air ratio in cases where engines are designed for natural gas. Also, controls are
recommended to maintain the desired fuel-air ratio at a relatively constant level, as energy content of the
incoming landfill gas may vary.
Approaches to carburetion with landfill gas-IC engines include the following:
• Monitor inlet methane concentration, and adjust fuel-air ratio accordingly. In principle, monitoring
should be frequent enough to track composition changes with reasonable speed and to allow
timely carburetion adjustments. This may or may not be possible in practice. The most
frequently used method of on-line landfill gas composition analysis is gas chromatography.
Methane content can also be measured (continuously) with infrared spectrography. An
alternative is continuous measurement of the calorific value (directly proportional with CH4) with
a calorimeter. Carburetion adjustments based on methane content are normally performed
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manually, although one system, Deltex™, is reported to employ an automated procedure (U.K.
Department of Energy, 1992).
• Base control on an exhaust oxygen composition set-point, and adjust air-fuel ratio to maintain
this. Oxygen can be analyzed in grab samples of exhaust, but sampling intervals are a limitation.
Alternatively, in-line exhaust oxygen sensors allow real-time feedback control. However, high
temperature sensors [>540°C (> 1000°F)] in engine exhausts have been reported to break down
quickly (probably because of halogens). The fuel mix may also be controlled by monitoring
carbon monoxide (CO) levels in the exhaust.
• Assess combustion time, which is an indicator of mixture composition and carburetion.
Technologies for this are under development.
Proper spark advance for the mixture and conditions is key to efficient engine operation. A typical practice
with natural gas-IC engines is to set spark advance to a constant setting or to follow a preset ratio.
Sometimes the spark setting is adjusted based on fuel/air composition, which requires appropriate
measurement and feedback. Whatever the fuel composition, maximum engine efficiency is normally
obtained with maximum advance (as long as detonation is avoided).
3.2.3 Lean-Burn 1C Engines
In "lean-bum" 1C engines, the air/fuel ratio is increased to lower the peak combustion temperature, thus
significantly reducing NOX formation. A general control problem relating to both carburetion and ignition
timing, is that sudden "fuel-rich" conditions may occur with swings in landfill gas energy content. This
condition can result in detonation and severe engine damage. There are two ways to guard against this
condition: strict fuel/air ratio control or feedback ignition timing adjustment. The latter is possible through
detonation-sensitive control, which advances the spark until slight detonation is detected, and then retards
it slightly; this normally results in optimum timing. Nevertheless, there are circumstances when fuel is too
rich and/or when combustion chamber volume is reduced by deposits, so that detonation will occur
regardless of ignition timing, and shutdown is needed to prevent damage.
The air supply to lean-burn engines must be pressurized by turbocharging. Turbocharger power is derived
from expanding engine exhaust gas in an expansion compartment (somewhat similar to the expansion
section of a combustion gas turbine). This expansion section is susceptible to damage from any deposits
associated with landfill gas use. Depending on where deposits form, they may flake off upstream of the
turbocharger and cause damage on ingestion, or build up on the blades or housing of the turbocharger and
cause damage. One approach to this problem is to replace the entire turbocharger assembly with a
cleaned spare at appropriate intervals, such as on each top-end overhaul.
Another problem can exist with turbocharging. Landfill gas is normally delivered at the energy facility at
near-atmospheric pressure. Both the gas and air must be compressed to (at least) intake manifold
pressure, which is well above atmospheric for lean-burn engines. One option, still standard practice, is to
compress the landfill gas and air separately, using a compressor for landfill gas and turbocharger for air,
and then to apply carburetion. In comparison, premixing of gas and air and subsequent turbocharging of
the mix can save capital and energy. This is routinely practiced in the United States with Caterpillar 3516
engines (Chadwick, 1990) and to a lesser extent with Waukesha engines.
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3.2.4 Field Experience 1C Engines
— Minimal Cleanup
In one case, early in the history of landfill gas energy (mid-1980s), 1C engines were operated by one major
energy equipment operator with cleanup limited to condensate knockout. Condensate knockout itself was
reported to be fairly inefficient so that some condensate was actually aspirated into the engine with the
landfill gas fuel, giving (as might be expected) poor results. Engines were stated to be "corroded out within
a few thousand hours." During the interval, when such minimal gas cleanup continued to be practiced, a
variety of design and materials modifications were applied to ameliorate problems. These included chrome-
plated valves, hardened piston rings, and others (further detail was not given). However, the operator
reported that, ultimately, operating experience only improved when refrigerated gas cleanup was applied.
After refrigerated gas cleanup [to dew points below 4°C (40°F)] was instituted at the sites in question, the
operator reported that top-end overhaul intervals improved dramatically (as high as 20,000 hours).
Minimal cleanup regimens, as described in the previous paragraph may suffice under other conditions. This
is shown by the experience with two Waukesha 7042 engines at the Marina Landfill in Monterey County,
California. This facility uses no gas cleanup other than interception of condensate and minimal filtration.
After the gas passes through the final field condensate trap, it moves through a riser via a small blower to
the engine manifold. The engine performance has been quite good. Analyses have indicated that the
landfill gas at this site does contain chlorinated hydrocarbon (analysis dates from 1980). Also, silica was
found in the engine oil. Thus, the relatively good performance of these engines, in spite of the practical
absence of cleanup, remains a puzzle.
— Limited Cleanup
A major operator using Cooper-Superior engines uses a condensate knockout before compressing the gas,
after which the gas passes through a coalescing filter. Care is given to maintaining the gas temperature
between 38°C to 66°C (100°F to 150°F). Other modifications and adaptations by the operator include the
following:
• Monitoring of methane content every 6 minutes by gas chromatograph (GC),
• Maintenance of methane at 47 to 52 percent volume,
• Use of a single compressor for field extraction and to serve the engines with a 620 kPa
(90 psi) gas supply,
• Natural gas supplementation (at some sites),
• Monitoring of cylinder head temperature,
• Automated computer monitoring of engine status,
• Automated panel for ignition control for each individual cylinder, and
• Control of engine to meet constant load.
The interval between top-end overhauls with this cleanup regimen is approximately 8,000 hours, which may
be considered as low. Cooper-Superior cites operating times of 17,000 hours for severe service and
25,000 hours in less severe service for their engines. In view of lower capital and operating expense and
absence of parasitic refrigeration load, this operator considers a low capital, less stringent cleanup strategy
preferable to refrigeration.
Natural gas supplementation is carried out preferentially at times of peak power prices to maximize
revenue. This appears to work well and is reported to result in smoother operation than with landfill gas
alone. Supplementation is through blending of the natural gas into the landfill gas stream.
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A problem that can occur when the engine is controlled to provide constant output is that misfiring of one
or more cylinders can cause the others to overwork, overheat, and eventually be damaged. The automated
control system detects such situations and allows their correction. There is more tendency for spark plugs
to foul and misfire when using landfill gas then compared with natural gas. No discussions of deposits
were presented by this operator.
Another operator, WMNA, has recently published details of its experience and has provided further
information in response to the survey conducted for this report (Markham, 1992). WMNA operates lean-
burn Caterpillar 3516 1C engines, mostly newer low pressure models (Chadwick, 1990). The gas
processing sequence is illustrated in Figure 8.
Incoming LFG
Y Remarks
Performance target of 95% entrained liquids removal
Roots blower [23-34 m3/min(800-1,200 cfm)]; Compressor
[approximately 240 kPa (35 psi)]
Design dewpoint of approximately 2~fC (8tfF) or 6-£f C above ambient
Filtration to 3 microns, and condensate removal
Reheating to ca. 11°C (20°F) above dewpoint
Figure 8. Simplified landfill gas flowchart for 1C engines (limited cleanup).
The positive displacement Roots blowers have carbon steel interior surfaces contacting landfill gas directly;
otherwise all components contacting gas are plastic, stainless steel, or epoxy coated carbon steel. It is
important to note that no refrigeration is practiced in the sequence above. Engine features and operating
conditions include:
• Chrome-plated valve stems/guides,
Jacket water 110°C to 116°C (230°F to 240°F),
• Oil: DA Blueflame™ type BG, nominal TBN 10 (see comments below),
• methane to engine monitored once/hour with Daniels™ GC,
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• Carburetion control to maintain 7 percent oxygen in exhaust (this is by hand-held meter
analysis),
• Exhaust gas temperature targeted below 650°C (1,200°F), maintained through adjustment of
engine operating conditions, and
• Spark set to 25 to 30 degrees before top dead center (BTDC); adjustments based on exhaust
gas temperature and spark is retarded if detonation is detected.
WMNA has compiled extensive operating statistics on its equipment application with the treatment regimen
above (Markham, 1992). On-line time has been 89 percent, when outages from all causes for these
engines are counted. However, gas supply interruptions due to gas field problems account for over half
(56 percent) of the outages. Under circumstances where gas availability is not the limiting factor, on-line
time has been even better (95.5 percent). Top-end overhaul intervals are on the order of 8,000 hours,
which matches Caterpillar's recommended interval. Typically, oil change intervals are conducted at 700
hours of operation.
The type of oil used (DA blueflame) is a modified natural gas engine oil chosen after WMNA's examination
of several types. Its total sulphated ash content (1 percent) and nominal TBN (10) are effective in
combatting corrosive compounds in the exhaust gas (Markham, 1992). An interesting aspect of WMNA's
operation is in-operation base replenishment. As the base that supports TBN is consumed by acidic
combustion products, more is added from treated oil bypass filters from which additional basic additives
slowly dissolve over time." However, a current disadvantage of the oil used is that the ash from the base
seems to contribute to deposits.
A difficulty, attributed to the combination of the degree of gas cleanup with use of the engine oil specified
above, is the buildup of oil ash and silica deposits in the combustion chamber, on the piston crowns, and
in components of the exhaust system. These deposits have several consequences:
• Over time they slowly decrease combustion chamber volume, and increase compression ratio
and tendency to detonate. (In fact this dictates the top-end overhaul interval);
• Chips of deposited material may flake off and damage the turbocharger expansion section;
• Particles can cause abrasion of parts such as valve stems and guides; once such wear
begins, it accelerates (apparently from increasing "blow-by") combustion of more oil and more
rapid deposition of oil ash, and wear, in a vicious circle; and
• Typically, the deposits are hard, so that removal requires power tools.
Tests are underway to determine if improved filtration, water injection, or use of ceramic coatings in certain
areas can overcome some of the deposit problems (Markham, 1992). Also, it is being determined whether
more stringent gas cleanup is warranted. Currently the trade-offs between disadvantages or debits of more
stringent cleanup and those of deposits appear close. Despite the problems, serious damage from deposits
is normally avoidable through timely overhauls. [See Markham (1992) for further discussion of deposits.]
— Stringent Cleanup
Lean-bum Waukesha and Cooper-Superior engines are operated by one major operator with cleanup that
includes refrigeration. The typical sequence is illustrated in Figure 9.
4 Personal communication, Chuck Anderson, WMNA, May 1992.
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Incoming LFG
f Remarks
Large diameter vessel with demister pad in upper portion
If two stages: normally, there is intercooling with a condensate trap
between stages
Gas cooled to 2?C
Fiberglass filtration, 0.1 to 1 micron cut-off
Reheat to above ambient, 24-3? C (75-901 F)
10 micron cut-off
Figure 9. Simplified landfill gas flowchart for 1C engines (stringent cleanup).
Engine operation practices include the following:
• Gas sampling by Gastech or GC, daily or less often;
• Carbon steel in some portions of process equipment (although it is being slowly replaced);
• Use of Mobil Pegasus™ 454 oil;
• Engine carburetion is based on exhaust oxygen content; measured inlet methane content,
and cylinder temperatures; and
• With Cooper engines an Altronics™ ignition controller is used to allow precision spark timing.
The experiences with engines on this regimen have been mostly good. Some of the problems that have
been observed concern changing landfill gas methane content. Oil changes are generally performed at
2,000 hours, which is considered excellent. Intervals between top end overhauls have been reported
asbetween 10,000 and 15,000 hours, which is regarded as very good.
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3.3 GAS TURBINES
In the United States, there are currently five operators using landfill gas in turbines; mostly Solar Saturn
or Centaur turbines. These are "standard" units with the exception that the combustors are modified to
permit necessary entrance of more gas. No materials modifications to the turbines have been made.5 For
all turbines, temperature control ("temperature topping") is necessary to prevent overheating of the blades
and to maximize power recovery. For landfill gas-fueled cases where energy content may on occasion vary
rapidly the fuel/air control must react rapidly, or temperature overshoot will occur. The temperature
overshoot will "trip" and automatically shut down the turbine. To prevent this—which is more an
aggravation, than a serious problem—the turbine may be operated at a slightly lower temperature set point
and efficiency than is normally the case with conventional fuels.
To reduce per unit investment costs, the capacity of a gas turbine should be large. However, when the
amount of gas decreases, so does the load factor of the gas turbine, resulting in very low efficiencies. If
such volume swings in methane are expected, an 1C engine may be a better choice.
3.3.1 Field Experience Turbines
Operating system "A" (WMNA). The sequence practiced by WMNA for gas turbines is illustrated in
Figure 10. The operating experience with the current system has been good. "As with 1C engines, WMNA
has kept detailed statistics for on-line turbine service. In 1991, average on-line time for WMNA gas turbine-
generators, considering outages from all causes, was 86 percent; on-line time was 93.9 percent, excluding
outages caused by well field/gas system problems.
One operating problem, outside the range expected with conventional fuels, has been with control of the
turbine.6 With "temperature topping" operation, automatic shutdown is triggered if gas temperature normally
exiting the combustor rises by only 15°F. With landfill gas, excursions to higher methane contents can
occur fairly easily. Consequently, WMNA operates the turbine at a slightly lower combustor temperature
than would be the case with conventional fuels, 25°F below the trip setpoint. This greatly reduces the
frequency of these outages (which, however, are brief). With an earlier gas cleanup system used by
WMNA for turbine operations, some serious operating problems occurred that are described in Schlotthauer
(1991). This paper is included in Appendix I.
Another company, Laidlaw, operates Solar Saturn and Centaur turbines at five sites. (All of these gas
turbine sites were purchased from a third party and have been managed and fully operated by Laidlaw only
since early 1992.) Details of one site, Sycamore Canyon, have been published as a case study in
Augenstein and Pacey (1992). The landfill gas cleanup sequence used by Laidlaw is illustrated in
Figure 11.
Personal communication, Robert Anuskiewicz, Solar Turbines, August, 1992; personal communication, Chuck
Anderson, WMNA, May 1992.
Personal communication, Chuck Anderson, WMNA, May 1992.
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Incoming LFG
Condensate
knockout tank
1
Wire mesh pad
I
Blower
I
Heat exchanger
Compressor
Separator
I3Z
Heat exchanger
I
Filter
I
Heat exchanger
Filter
To Turbine
Underground
Stainless steel
First part of 2-stage compression, rotary lobe type
Interstage cooling against atmospheric air
Second part of 2-stage compression, using oil lubricated screw
Separates oil from compressed gas
Gas cooled using fin-fan cooler
Condensate removal
Reheat to 11-22 C (20-40 F) above dewpoint
Using Pall process filter to 0.3 micron absolute
Figure 10. Simplified landfill gas flowchart for gas turbines (example 1).
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Other operational aspects practiced by Laidlaw are:
• Temperature topping operation,
• Recuperation of turbine exhaust gas against inlet air (with smaller Saturn units, only),
• Automated shutdown when oxygen exceeds 3 percent, and
• Precooling of turbine inlet air during hot weather (at some sites).
According to Laidlaw the performance of the turbine systems has been good. The gas processing system
initially designed by Solar appears to have avoided contaminant/oil related problems of the type reported
by WMNA at some sites.
Incoming LFG
Condensate
knockout tank
Coalescing filter
To Turbine
Solar
10 micron cut-off
To about 1,200 kPa (175 psi) using Solar-Howden
2-stage oil-flooded compressor
Removes oil from compressor
Cooling against atmospheric air
Of post-cooling water
Reheat to approx. 20°C (35-40°F) above dewpoint
Figure 11. Simplified landfill gas flowchart for gas turbines (example 2).
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3.4 BOILERS
This section discusses landfill gas utilization in direct use boilers, as well as in steam boilers. The largest
boilers using landfill gas are those raising steam for steam turbines at steam-electric power plants.
With direct combustion and boiler applications, the most common approach is to apply minimum gas
cleanup, limited to condensate knockout and optional filtration. To date, this has appeared to work well
for most boiler applications. Boiler tubes, that might be considered potential candidates for fouling or
corrosion, appear to experience no undue amount of either. The only corrosion reported has occurred on
boiler door fittings and on external tubing to auxiliary equipment, such as pressure meters. All of these
parts can be easily and inexpensively replaced. Design adjustment however, needs to be made for the
lower energy content of the landfill gas flow (approximately 500 vs. 1,000 Btu/scf for natural gas). This may
be achieved by doubling the gas pressure (with a larger compressor), or by doubling the burner orifice area.
It is generally more economical to limit pressure requirements at the boiler and keep the whole system at
a lower pressure. At the Palos Verdes Landfill gas steam turbine facility of the Los Angeles County
Sanitation District (LACSD) the size of the landfill gas fuel piping and valves was approximately doubled
over the natural gas piping system to reduce the landfill gas pressure requirement to 2 psig. Lowering of
the operating cost of the pressure drop for the landfill gas system pays for the larger piping system many
times over (Eppich and Cosulich, 1993).
With natural gas-fueled boilers and other direct use processes, fuel metering can be accomplished by
simply maintaining a constant flow ratio or, when finer control of air/fuel ratio (trim) is desired, by
maintenance of a desired (low) oxygen level in the stack gas. For landfill gas the methane content can
vary significantly, therefore the maintenance of a constant volumetric flow ratio of landfill gas/air is a less
than satisfactory method. Stack gas oxygen monitoring for trim can be done with grab samples using a
portable gaseous oxygen sensor. Frequency with which stack gas can be sampled using a portable meter
is normally limited. In contrast, continuous in-stack oxygen monitoring sensors can allow continuous
feedback control of air/fuel ratio in the optimum range. Such sensors are reported to give very acceptable
service lives of several years (at least); this is interesting in view of the reported limited lifetime of such
sensors in the exhaust gas of 1C engines. If rapid landfill gas composition changes occur, oxygen
measurement and control may be too slow, particularly for larger boiler systems; feed forward control
(measuring methane or heat content) is then recommended. On the whole, the trim systems, which adjust
air/fuel ratios based on oxygen sensed in the exhaust, seem to work well.
Largely due to the presence of a significant amount of CO2, flame front propagation through the landfill
gas/air mix is slower than with a natural gas/air mix. For proper combustion in burners, the flame front
must propagate faster than the gas flows away from the burner. Under circumstances that occur with some
types of burners (e.g., conventional space heating), the flame may lift from a burner orifice, or with very low
methane gas levels, go out, if the flame front propagates too slowly. Such problems are, however,
infrequent.
Eppich and Cosulich (1993) indicate that the CO2 in landfill gas has the beneficial result of reducing
formation of (NOX) and decreasing the amount of flue gas recirculation required to achieve a given NOX
emission level. NOX emission from LACSD landfill gas fired boilers with flue gas recirculation are typically
16 to 24 parts per million by volume (ppmv) at 3 percent O2 (dry), well below established regulatory
requirements. The boiler's flue gas recirculation system effectively reduces NOX by 50 percent.
To increase thermal efficiency, larger boilers and, in particular boilers for steam-electric plants may practice
recuperation of exhaust stack heat with incoming air in a heat exchanger. Where a boiler is combined with
a heat exchanger (often referred to as super-heater or economizer), such as at a steam turbine facility, the
lower landfill gas flame temperature resulting from landfill gas CO2 presence may result in lower flue gas
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temperatures, and this may require use of a larger super-heater than would otherwise be needed for a
natural gas fuel boiler (Eppich and Cosulich, 1993). In some cases, fouling problems have been reported
with super-heaters. Deposits on recuperators (economizers) employing multi-finned tubes have been
witnessed. Deposit buildup in interstices has interfered with heat exchange. Eppich and Cosulich (1993)
indicate that these problems have not occurred with the LACSD steam turbine projects. Some dust on the
boiler tubes was noticed, however, this dust could be easily brushed off.
During combustion of landfill gas, the sulfur compounds in the landfill gas are converted to SO2 and SO3
and trace amounts of chlorine from chlorinated hydrocarbons are converted to hydrochloric acid (HCL).
The SO3 in the flue gases raises the condensation point to approximately 280°F. If the temperature in the
air preheater drops below the condensation temperature, problems can occur. As acid gases in the flue
gas concentrate in the condensate, they will corrode both carbon and stainless steels in the gas path. This
issue can be addressed by component replacement, or prevention of the condition. On/off cycling poses
some danger of corrosion from the exhaust condensate, that can condense in cool-downs between service
periods.
3.4.1 Field Experience Boilers
A landfill gas-fueled steam boiler, that supplies 24,000 Ib/hr (at peak output) of steam to a pharmaceutical
plant in Raleigh, North Carolina, has been described in Augenstein and Pacey (1992). Minimal gas cleanup
is employed (condensate simply drops out of a low point in the 3/4 mile gas pipeline supplying the plant).
The boiler is equipped for multi-fuel operation, incorporating a landfill gas burner ring and separate
dedicated oil and natural gas burners. No operating problems related to landfill gas use have been
observed and this boiler has functioned well to date. At the LACSD's Palos Verdes steam turbine facility,
landfill gas is delivered to the boiler at a CH4 content of 20 percent (approximately 200 Btu's per cubic foot),
or less. This low methane content can result in flame instability. Natural gas supplement is sometimes
used to stabilize the flame. Redundant flame monitors are wired to a voltmeter above the operator's main
control board to detect the boiler flame. If the voltage begins to fluctuate, the operator takes corrective
action, such as increasing injection of natural gas, decreasing the flue gas recirculation, or decreasing the
vacuum on the landfill.
Details of design and operation of a 46 MW power plant in the Los Angeles Basin are presented in Eppich,
et al. (1990). Landfill gas fuel composition is tested continuously with an on-line calorimeter to enable fuel-
air ratio control. Problems relating to landfill gas itself are reported to be minor. Some landfill gas-specific
problems included burner safety management "trips" and plant shutdowns due to a flame detection system
that did not always sense the cooler landfill gas flame. Flameouts also occurred when landfill gas energy
flow fell to 200 Btu/scf (equivalent to approximately 20 percent methane content) upon landfill gas piping
breaks. One outage occurred where air preheater fouling, with deposits consisting mainly of silica, required
cleaning of the tubes. However, the operators of this plant seem to be satisfied with its overall
performance.
Another landfill gas fueled steam power plant is operated in the same general vicinity of the plant directly
above. This plant has a nameplate capacity of 20 MW, but due to limited gas supply, generates an output
of 15 MW. Relatively few other details were obtained. With this plant, recuperator deposits built up to
cause problems similar to those above; in addition, an indirect problem resulting from the deposits was
corrosion. This problem has been overcome by replacing the original heat exchanger with a new indirect
exchanger that uses Dowtherm™ as a working fluid. The staff of both steam-electric plants described
above indicate that steam electric generation using landfill gas is a highly satisfactory approach for those
situations (large recovery rates).
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3.5 LANDFILL GAS PURIFICATION TO PIPELINE QUALITY
Landfill gas cleanup to pipeline (natural gas) quality has no very close analogue with conventional fuels,
but has some similarities to "sour" (high H2S/CO2) gas cleanup in the natural gas industry. The principal
differences between sour natural gas and landfill gas cleanup are posed by compression issues (sour gas
at the wellhead is already at high pressure), and the need to remove halocarbon compounds that are not
present in sour gas. Halocarbon compounds—along with other compounds—can be removed by cleanup
with sorbents, of which activated carbon is the most common.
The GSF energy division of Air Products and Chemicals, Inc. is the principal entity in pipeline gas
preparation [although Browning-Ferris Industries (BFI) and Gas Resources Corporation also have plants].
The Gemini™ process used by GSF, in very brief overview, comprises:
• Refrigeration to remove condensate,
• A solid sorbent pretreatment system employing activated carbon, iron sponge, and other
sorbents to take out the contaminants other than CO2, and
• Pressure-swing absorption CO2 removal.
For both pretreatment and CO2 removal, multiple fixed-bed columns are used and regenerated in a
batchwise-continuous fashion [gas cleanup is done by columns with fresh sorbent while other columns are
regenerated off-line (Koch, 1986)]. The conclusion of GSF, after operating the process since 1986, is that
it has been a very satisfactory method for pipeline gas preparation. The molecular sieves used for the PSA
would be susceptible to damage were certain landfill gas NMOC contaminants to reach them; however, the
pretreatment step has been highly effective. Until now, no molecular sieve column at any site has needed
to be replaced since 1986.
A second approach for pipeline gas preparation is the Kryosol™ process using chilled methanol as the
sorbent (Markbreiter, 1983). The only report on this process, from one operator who has operated a
system since 1986, is that their system—after much upgrading of gas field and piping unrelated to the plant
itself—has performed "quite well." A very similar approach is the Selexol™ process that uses glycol (Shah,
1990).
A general consideration with gas purification processes is that nitrogen and oxygen contained in the landfill
gas must be limited, since none of the processes listed above can remove them. This must be
accomplished by well monitoring, and maintaining extraction rates and vacuum pressures low enough so
that nitrogen/air entrainment into the gas is avoided. GSF's experience demonstrates that this can be
accomplished to meet pipeline gas preparation constraints.
Appendix E describes a pilot project in the Netherlands where "waste" CO2 from a landfill gas purification
project is upgraded to liquid or solid ("dry ice") CO2 suitable for commercial purposes. The study concludes
that upgrading of CO2 from landfill gas purification projects to marketable quality is technically, as well as
economically, feasible in the Netherlands.
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4. NON-TECHNICAL CONSIDERATIONS
This section of the report presents non-technical barriers that are associated with landfill gas recovery and
utilization as encountered by the landfill gas utilization industry. It is hoped that the information presented
here will contribute to a better understanding of the perspective of private developers/operators among all
parties involved with landfill gas utilization. These parties include but are not limited to: public and private
landfill owners; local, state and federal regulators concerned with solid waste, water quality, air quality, and
global warming issues; financial institutions; and utilities. The use of landfill gas can only be increased if
all parties are aware of each others viewpoints and objectives and participate in fruitful communication.
This document is not intended to provide a comprehensive overview of the many different perspectives of
all parties involved. Instead, it is limited to summarizing the experience of current private developers and
operators in an effort to provide information to the public and more in particular, to assist future developers
and operators in developing landfill gas utilization projects. Consequently, this document will also present
the issues from the industry's perspective and it will not necessarily reflect the views of the authors, nor of
the U.S. EPA.
To obtain pragmatic and recent information, interviews were conducted with seven developers and/or
operators of landfill gas energy projects, including:
• Palmer Capital Corporation; midsize developer of boiler, engine, and pipeline quality gas projects
since 1983,
• BFI; solid waste management firm with 5 in-house landfill gas utilization projects,
• Rust Environment and Infrastructure/Waste Management of North America (WMNA); large
developer and operator,
• Energy Tactics; midsize developer and operator of landfill gas to electricity projects,
• Granger; small to midsize developer operator,
• Laidlaw; large developer and operator of turn-key projects,
• Pacific Energy; small operator.
Write-ups of the interviews are included in Appendix D, whereas a summary is included below. Statements
of interest are referenced by including the name of the interviewed company in parentheses. Aside from
possible non-technical barriers other possible considerations for potential developers or operators of landfill
gas energy conversion projects include 1) choosing between energy utilization options; 2) organization and
management of the project; 3) incentives to encourage landfill gas utilization, which are discussed in
section 4.2.
— Choosing between energy utilization options
Energy utilization options include direct use in boilers, cement kilns, etc., to produce heat; as fuel for 1C
engines and gas and steam turbines in the production of electricity; and as a feedstock for producing high
Btu quality gas for use as equivalent natural gas. These options, and others under development, are
discussed in detail in "Landfill Gas Energy Utilization: Technology Options and Case Studies"
(Appendix A). In general, the direct firing option (e.g., boilers) is the least costly and most favored.
A detailed discussion on choosing between different options for landfill gas utilization is beyond the scope
of this report. However, some guidance is provided in Appendix E and H. Appendix E includes a section
from a British document entitled: "Quality Assurance and Risk Management." Although written from a
different perspective, it gives an excellent generic overview of the issues involved with sound landfill gas
project management, indispensable in any decision making. Appendix H includes a paper entitled:
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"Selecting Electrical Generating Equipment for Use with Landfill Gas." This paper compares technical as
well as operational and economical considerations, for 1C engines, steam turbines, and gas turbines.
— Organization and management of the project
There are many variations in the position the owner/operator can take in regard to development of an
energy conversion project on a site. Those interviewed stated that successful energy recovery projects
appear to embody the following key elements:
• They are run by experienced professional management;
• They are adequately financed so that labor, inventory, and supplies are on hand as needed;
• They have an excess landfill gas supply, and favorable marketplace;
• The landfill is active and remains so for 5 to 10 more years;
• Contracts for the gas rights, power, or gas, sales and facility use are solid and of proper term;
and
• The project should have experienced personnel, and backup, for servicing of the landfill gas
extraction system and the energy conversion system.
Today,'some companies provide turnkey design/construction for energy conversion units and will provide
the operation and maintenance activity as well; some provide the same turnkey service for the extraction
systems. While the service industry is not big, it is adequate and growing to service the needs associated
with the CAA. Appendix C includes a list of landfill gas developers and landfill gas operating companies
in the U.S.
Appendix E includes a section from a British document entitled: "Quality Assurance and Risk
Management." This paper might be of merit to landfill owners who either want to develop a landfill gas
project themselves, or to monitor the progress of a contractor. It gives a breakdown of the different phases
of a landfill gas project; from feasibility study to shut-down. Also, it provides check-lists of different tasks
and responsibilities for participants. Appendix G gives an overview of the issues involved in planning and
constructing a recovery system for existing landfills.
4.1 BARRIERS
A barrier as presented here is an issue, hurdle, or project stopper. What may be an insurmountable barrier
to a first time landfill gas project developer may not be a barrier to an experienced developer.
U.S. barriers that were identified from the series of interviews conducted for this report include:
• Unfavorable economics due to low energy prices and high debt service rates for landfill gas-to-
energy projects that generate electricity or pipeline quality gas;
• Limited or unstable marketplace;
• Obtaining third party project financing at reasonable cost as it is difficult, time consuming, and
proportionately more costly for small projects than for large projects;
• Difficulties in obtaining air permits, especially for projects located in ozone and CO nonattainment
areas, as air boards and utilities often have lengthy permit processes and contract negotiations;
• Difficulties in negotiating power contracts with local utilities as they are primarily interested in
purchasing low-cost power without considering environmental externalities (e.g., offsets from
power plants using fossil fuel). [However, the environment has changed somewhat as a
consequence of State Public Utility Commissions (PUCs) who mandate that utilities only pay
avoided cost for electricity purchases];
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• Unforeseen costs resulting from compliance with new air quality rules and regulations, and
declining energy revenues that cannot be adjusted to offset new costs;
• Taxation by some states, such as California, on landfill gas extraction and energy conversion
facilities; and
• Difficulties in understanding Federal and State energy policies and environmental regulations that
may affect these projects.
— Financing
Lenders, such as banks, typically work with a minimum lending package of approximately $10,000,000.
Other lenders for small loan packages may offer mezzanine financing where, if available, will generally be
2 percentage points higher then bank interest rates (Palmer). It is important to note that small projects
require almost as much loan administration and due diligence work as the large projects (PEN). In this
sense, the small project is at a significant penalty because proportionally higher finance costs must be
spread over a much smaller revenue stream. This fact alone has been a reason why many small projects
have not been financed.
Some lenders have limited experience with landfill gas projects and the applied technologies. Typical
concerns of lenders in regard to landfill gas projects include:
• The small size (Palmer, Laidlaw, PEN), typical lenders are interested in projects of $10,000,000
or more, whereas landfill gas projects rarely represent more than $5,000,000;
• Environmental compliance and liability (Palmer, Laidlaw, PEN);
• Landfill gas supply reliability over the term of the contract (BFI);
• Equipment performance;
• Management experience, capacity, and continuity;
• Cost stability and unexpected costs (retrofits, new rules and regulations, taxation, etc.) (Palmer,
Granger, Laidlaw, PEN); and
• Contract constraints and inflexibility.
In order to proceed with a project, a developer usually needs an up-front financial commitment. Because
of the complexity of the due diligence, it may take considerable time and negotiation to obtain a financial
commitment, particularly when some issues such as cost of interconnect (to a utility grid), and obtaining
of some permits, may not be resolved prior to financing commitments (ETI, Granger, Laidlaw, Palmer).
Loan guarantees required by lenders can be demanding (ETI .Granger) and attachments to non-project
assets may be required. In one instance, the lender required 62 signed documents as part of the loan
package (Granger).
— Penalties Associated with Landfill Gas as a Fuel
California utilities (PG&E, SDG&E, and Southern California Edison) are auctioning future electricity capacity
with preferential set-asides for renewable energy projects. These projects include landfill gas. However,
landfill gas is penalized for the CO2 content in emissions from engines (BFI, Laidlaw, Palmer, PEN). This
penalty amounts to approximately 1.5 cents/kw (Laidlaw). The developers consider this unfortunate
because the soon to be promulgated CAA regulations for landfills will require that the landfill gas be
collected and either flared or combusted in energy conversion equipment at those sites targeted for control.
If it is assumed that combustion efficiences of a flare and a utilization process are similar, the CO2
emissions are equal. Therefore, if the landfill gas were to be redirected through an energy conversion
combustor/generator set, instead of being sent to a flare, no new CO2 emissions are being created.
Accordingly, a landfill-gas-to-energy project should at least be on a comparable basis as solar, wind, and
geothermal projects. The developers think that the government (Federal, State, and local) should assist
the impacted landfills by ranking landfill gas-to-energy projects above competing renewable energy fuels
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such as solar, wind, and geothermal to help defray some of this imposed cost burden for landfill gas
projects that currently has no offsetting revenue increase (BFI, Laidlaw, Palmer, PEN). According to the
developers, the action of the utilities in penalizing landfill gas projects for its CO2 emissions will make it
difficlut for landfill gas to electricity projects to win any bids for new capacity in California.
The developers think that because of low energy prices and additional barriers to development of landfill
gas projects, the landfill owner/operator may become an involved partner with a prospective landfill gas
energy developer. The landfill owner/operator may have to provide all, or a portion, of the costs and
management associated with the extraction system; at least during the economic life of the energy
conversion project term. After this period, the owner/operator has the full burden of the gas
extraction/control system (Carolan, 1994).
— Communication with Government Agencies
While there are typically only one or two Federal agencies (EPA and OSHA) interested in landfill gas
projects, there can be numerous State and local agencies involved in a landfill gas project, including those
concerned with air quality, water quality, solid waste and hazardous waste management; worker safety; tax
assessment; and building and site improvement.
Delays in obtaining permits from State and/or local air pollution control agencies to construct landfill gas-to-
energy projects is considered a barrier. Lenders are cautious about providing up-front loan commitments
when the time and cost for obtaining permits is uncertain (Palmer, BFI, ETI, WMNA, Laidlaw). Delays in
the permitting process increase costs and uncertainty in whether or not a project will be approved by an
air agency. The time for obtaining a permit may range from a few months to well over a year depending
on an air agency's permit requirements, work load, and regulations (ETI). Delays in the permitting process
are frequently caused by a lack of clear guidelines for what must be included in a permit and concerns of
the agency and the public. In addition, the number of regulations with which a project must comply also
affects the length of the permitting process. For example, in California there are a number of regulations
that affect landfill gas projects including AB 2588, Rule 834, Rule 436.1 for H2S, Rule 1150.1 for landfill gas
retrofits for NOX reduction, and the new operating permits required under Title V of the CAA.
Projects that will be located in air basins designated nonattainment for ambient air quality standards for
ozone, CO, or NOX are being required to comply with new regulations and policies to control emissions to
bring the air basins into attainment. Delays in preparing the new regulations and in understanding their
requirements creates uncertainty and delays in the permitting process. For example, in ozone
nonattainment areas, landfill gas-to-energy projects may be subject to control requirements for nonmethane
organic compounds and NOX which increase the time and cost of the permitting process as well as the cost
of controls for the project.
For projects that are considered major sources of one or more pollutants, difficulties can arise in defining
the control technology to meet lowest achievable emissions rate requirements under new source review
regulations or best available control technology (BACT) requirements to meet prevention of significant
deterioration regulations. For example, some local air agencies in California consider flares as BACT for
landfills. Combustion of landfill gas in equipment designed to produce energy is not considered BACT
because the agency is only concerned with controlling the pollutants for which the project is major (e.g.,
nonmethane organic compounds or CO), and does not consider the relative the benefits associated with
controlling methane to produce energy (PEN). An example of conflicting rules is the Californian Rule 131.1
that states that no fuel can be burned with more than 40 ppm of sulfur compound (for instance H2S); yet
there is also a requirement that the landfill gas must be burned (PEN). What if gas from a particular landfill
exceeds the 40 ppm sulfur limit?
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— PUCs and Utility Companies (Utilities)
The Federal Energy Regulatory Commission (FERC) recently ruled that it was unconstitutional for utilities
to pay for electricity at a cost above their avoided cost. This ruling was passed through the State PUCs
to the utilities and has made the generation and sale of electricity to utilities an open and mostly free
market. Some states have provided some incentive packages that apply to landfill gas-to-energy projects,
however, these have limitations as to availability and qualification. Those interviewed state that in an open
and free marketplace, landfill gas to energy projects cannot compete as the break-even rate is in the range
of 5 to 6 cents/kwh and the avoided cost today is believed to be about 2 to 3 cents/kWh.
Interconnect costs to utility grids range in value from $10,000 for an older 1 MW project to $1,500,000 for
a 15 MW project (ETI, Laidlaw, Palmer, PEN, WMNA). Costs have increased significantly over the past
5 years. The cost estimates tend to rise as the project plans and details approach finalization. The utility
will usually install the interconnect and may not accept the developer's design and suggested cost
reductions. The costs are usually higher for projects in rural and remote areas as line capacity and grid
are subject to greater relative charges.
Utility companies will work with a developer, but need a realistic set of plans and details to determine
interconnect design and cost. Costs may be high reflecting the utilities desire to do a good job and not
have to escalate the initial cost estimate. Nevertheless, developers have had numerous cost escalations
as the project took shape. Often final cost may not be available until the project is almost on line, a
condition which is bothersome in arranging early financing.
— User Conception of Landfill Gas
A number of developers has found that some potential boiler clients perceive landfill gas as an undesirable
fuel. For example, a boiler user may be unfamiliar with landfill gas characteristics, energy value, and
reliability. Also, potential clients may have increased costs associated with landfill gas use as a
consequence of regulatory involvement, fire and safety issues, condensate management, and equipment
maintenance issues, etc. (Granger, Palmer). It may be necessary to obtain right of way permission for the
pipeline and make sure that the local utility is friendly and does not oppose the project (Granger, Palmer).
It may also be necessary to educate such clients and associated parties that the gas is safe to use and
the equipment only needs minor modifications for use of the landfill gas.
— Market Selection
The marketplace for a landfill gas end-use project is limited to the landfill vicinity, usually within a distance
of a few miles. Occasionally a greater distance has been achieved, which requires very specific conditions.
Issues with developers include: whether the contracted quantity of landfill gas can be assured for the
contract term at 7 days/week, 52 weeks/year; whether the users are stable and will be around for the
contract term; and whether there is flexibility in the contract for revenues to be adjusted for unforeseen cost
additions related to new rules, regulations, and required retrofits responding to environmental mandates.
— Rules, Regulations, and Taxation
A first time landfill gas-to-energy project developer will find a myriad of Federal, State, and local agencies
and rules, regulations, and tax assessments with which to contend and understand (Laidlaw). It is
mandatory that a developer get proper guidance and education on these issues relative to undertaking such
a project. Existing developers or consultants should be sought out for discussion and educational purposes
to determine the agencies, rules, and regulations affecting such projects and to assess the pros and cons
of undertaking such a project. New rules or regulations can result in unforeseen retrofits, increased
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monitoring, and added assessments; all adding unforeseen costs. There is generally no possible revenue
increase to offset this cost (Laidlaw, PEN).
Landfill gas-to-energy projects are of benefit to society and the environment. On this basis, many states
exempt them from taxation, partially or fully. Other states, for a variety of reasons, assess secured,
unsecured, and possessory taxes upon all site property [(extraction system, gas reserves, and on-site plant
and improvements) Palmer, Laidlaw, PEN]. These levies can be significant and have led to the elimination
of some potential landfill gas projects.
— Costs of Condensate Disposal
Where condensate can be disposed to existing leachate systems or sewer systems, disposal costs should
be relatively low. However, if the condensate cannot be disposed in this manner, costs can range up to
$1.00 per gallon; this could discourage a landfill gas project (PEN, Laidlaw).
4.1.1 Selected Case Histories
— New England Power Company
The New England Power Company "Green Request for Proposals" case study illustrates that
a utility can play a key role in encouraging landfill gas energy recovery, and gain significant
benefits from doing so. At the same time, this case study shows the need to educate public
utility commissions about the value of landfill gas energy recovery projects, and the need for
project developers to seek the most cost-effective project designs.
In .December of 1991, New England Power Company (NEP), the wholesale generating
subsidiary of the New England Electric System, issued a Green Request for Proposals (RFP)
for energy from renewable resource technologies. Within the framework of long term corporate
planning, the Green RFP was designed to allow NEP to assess the potential of renewables
in New England and to stimulate their commercial development. This move, the first of its kind
by any utility in the U.S., was designed to generate environmental benefits and test "green"
electricity sources for cost, reliability, and future expansions. It is expected that these plants
will help NEP obtain its goal of significantly reducing air emissions and, in particular, of
reducing greenhouse gas emissions by 20 percent by the year 2000.
NEP clearly recognized the benefits of landfill gas energy recovery, and the role these projects
could play in its energy strategy. In August 1992, NEP made the following statement its New
Renewable Energy Initiative - Objectives and Experiences:
"The RFP, however, reveals that there are still opportunities available for landfill gas
generation expansion. Due to the fact that the potential sites are widely distributed,
landfill derived methane resources can yield local benefits to many communities
while easing transmission and distribution loss by offsetting local loads. The
opportunity to reduce methane emissions (which are considered to have a potential
impact up to 21 times that of CO2 on global climate change) makes landfill
generation an attractive option for addressing the NEP goals."
From the solicitation, NEP received 41 bids representing over 1.4 million MWhrs of annual
generation from solar, small hydro, advanced wind, landfill produced methane, biomass, and
waste-to-energy projects. Many viable small hydro and landfill gas project bids were received.
Although all projects exceeded NEP's forecast at the time for avoided costs, NEP was satisfied
that the potential educational and environmental benefits made investment in these projects
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worthwhile. In fact, when environmental benefits were considered, NEP concluded that the
value of these projects substantially outweighed their cost.
On July 22, 1993, NEP issued a statement that it would purchase 36 MW of electricity from
seven renewable energy plants, including four landfill methane combustion projects (three in
Massachusetts and one in New Hampshire) with a combined capacity of 13 MW. The
statement included the following comment:
"Landfill methane combustion, one of the selected technologies, provides
environmental benefits from using methane gas that otherwise would be released to
the environment. The methane is produced as the solid waste decomposes in
landfills. If the methane was released without combustion, it is considered to have
as much as 20 times the contribution to potential global warming as carbon dioxide,
a byproduct of the combustion process."
NEP's next step was to obtain approval from the public utility commissions in its service
territory, which includes the states of Massachusetts, Rhode Island, and New Hampshire. The
successful project developers had signed power purchase agreements with NEP with provisos
that the contracts were to be approved by the PUC in each of the three states.
The New Hampshire PUC was the first to address these projects. They initially rejected all
landfill methane recovery projects, contending that NEP would be paying too much above
avoided cost, and that the projects did not demonstrate new technology. -The New Hampshire
PUC also felt that because the landfill gas may have to be collected and either flared or used
in the near future, the projects would not convey environmental benefits beyond what will be
required by the new landfill regulations. The PUC also had concerns about establishing a
precedent for paying more than the avoided cost. The result was that the developers agreed
to pay New Hampshire consumers the difference between NEP's current projected avoided
costs and the developers' contract price, since only a very small portion of the power
generated from landfill gas would be consumed in New Hampshire.
The Rhode Island PUC reviewed the Green RFP proposals several months later and rejected
the alternative energy applicants, arguing that NEP should not pay the developers more than
NEP's avoided cost.
Although the Massachusetts PUC staff had indicated its approval of the Green RFP alternate
energy projects, NEP chose not to proceed without approval from the Rhode Island PUC.
NEP acted to cancel its contracts with landfill developers. However, both NEP and the
developers were willing to renegotiate the power purchase contracts. As a result, the parties
agreed upon revised project cost figures, which were presented to the PUCs. Ultimately, all
projects were approved by the three PUCs. The results of this process — the PUC approvals
and the developers' renegotiations — are:
• the projects are proceeding,
• the developers will make less profit than originally planned, and
• the projects start-up dates were delayed by about 1-1/2 years.
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Several lessons can be learned from this case study:
• PUCs need to be educated about the benefits of landfill gas energy recovery. To
address this informational barrier, EPA's Landfill Methane Outreach Program is
providing information to commissioners. The National Association of Regulatory
Utility Commissioners endorsed the Program in March 1994;
• Utilities, such as NEP, considering renewable energy purchases above avoided cost
should consult with their PUCs early in the process and be prepared to respond to
any PUC concerns;
• Project developers should carefully consider all the options for structuring projects
at the least cost and look for opportunities to work with the utility to gain PUC
approval.
— Michigan Township
A Michigan Township Supervisor raised an issue as to whether the extraction and use of
landfill gas qualified the project for taxation exemption. The Township elected to take issue
with the exemption clause in Public Law 2, recently enacted to help facilitate renewable energy
projects. The Township was concerned with whether the clause applied to an electricity
project. The State had not clearly defined what was a qualifying facility and the decision
therefore rested with the local community. The community interpreted the law to place the
project in a position of a solid waste management facility that was non-exempt. The result was
a 2-year legal dispute, including court action. If the State, or federal agency, were to clarify
the environmental posture of a landfill gas recovery project, then such an issue would probably
not arise in the minds of state, or local authorities (Granger). The plant was actually
constructed and operational during this 2-year dispute as the circuit court judge allowed the
project to be operational under certain constraints. Nevertheless, such court action causes
delays and adds costs, which may become difficult to bear for a smaller, less experienced
developer.
— San Marcos Landfill, CA
The County of San Diego owns the San Marcos landfill and is expanding it vertically. The
State Solid Waste Management Board required that an impervious liner be placed between
existing refuse plan grade and the vertical addition. The site has an operating gas extraction
system in place that would be impacted by the vertical rising. The Solid Waste Management
Board wanted the extraction system to be buried with all existing lateral and header piping to
be installed laterally so that the piping would underlie the new barrier, without penetrations.
The Air Board intervened to require vertical extension of the existing wells with use of
appropriate sleeves where penetrations occurred. This was finally approved but with the
caveat that a significant layer of clay be used on all penetrations to improve seal performance.
This negotiation took time, added costs and demonstrated that agencies can have a significant
impact on project retrofit, or expansion.
4.2 INCENTIVES
U.S. incentives for undertaking landfill gas projects include:
• Purchase of electricity at avoided cost of between 2.5 and 3.0 cents/kwh, except where a
utility offers a special incentive program, consisting of a levelized higher price, and/or capacity
entitlement,
• Production Tax Credits (PTCs),
• Favorable utility contracts for electricity projects,
• Tax exemptions for landfill gas extraction and energy conversion facilities,
« Technical assistance from EPA's Control Technology Center, and
• New initiatives from the Department of Energy and EPA, discussed under 4.2.1.
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Production Tax Credits are available to a tax paying entity that has the rights to sell the landfill gas and
does sell it to an energy user who purchases the landfill gas and converts it to energy. These credits are
proportional to gas energy delivery as legislated by Congress (Section 29 of the IRS Code) in 1979 to
encourage non-fossil fuel use. Today, these credits amount to the equivalent of approximately $0.01/kWh
and they increase in value at approximately 4 percent annually. To obtain an indication of the PTC dollar
value for a given project, a chart is shown in Figure 12. With this chart, PTCs for a given landfill gas flow
(mmscfd), methane concentration (%), and energy value (price of barrel of oil equivalent) may be
calculated. Another chart (Figure 13) converts landfill gas flow in mmscfd into electrical output in MW, by
making use of the heat rate of the gas in Btu's per kW.
Some states have mandated that utilities purchase a portion of their new capacity from renewable energy
sources, including an allocation for landfill gas, some utilities have provided the same scenario. However,
some utilities penalize landfill gas for the carbon content in the exhaust of the engines, or turbines. Most
of the state and utility new capacity incentive opportunities are spoken for at present. The incentive
Pioneer Rate of approximately 6 cents/kWh was offered by utilities in New Jersey, New York, and
Pennsylvania from 1984 until about 1992; the favorable 1984 Standard Offer Four contract was offered by
California utilities for about 1 year, many of these Standard Offer Four contracts are coming to the end of
their favorable pricing and capacity entitlement revenue stream.
Additional incentives are sometimes offered by state mandate to the utility .companies, or directly by a utility
company, to contract for a stated amount of capacity at a favorable rate from landfill gas sources. In
evaluating the viability of the project the developer first assesses the potential revenue stream which
consists of the current avoided cost of 2.5 to 3.0 cents/kWh, plus the value of the PTC which is now about
1.3 cents/kWh and any capacity entitlement, which vary from 0 to about 1 cent/kWh, depending upon the
utility's need. All revenues and costs are expected to rise in future years to keep up with inflation, or some
accepted measure of inflation.
However, if only the avoided cost and PTC are available, the revenue stream consists of 2.5 to
3.0 cents/kWh plus a tax credit equal to 1.3 cents/kWh. This is not considered enough by some landfill
gas developers to justify development of a project. Most developers assert that a cost basis for breakeven
is'4.0 to 6.0 cents/kWh for large and small projects respectively assuming they pay no royalties and the
landfill owner is responsible for the landfill gas extraction system. Royalties paid to landfill owners have
ranged up to 15 percent of revenues when revenues are in the 7 to 8 cents/kWh and are little if anything
as the range falls below 5 cents/kWh. One option to obtain a higher initial energy sale price is to negotiate
a levelized, or phased price basis with the utility such that the developer obtains a higher than avoided cost
payment in the early contract years in exchange for a lower than avoided cost in later years as the capital
debt is paid off. Other creative options may be necessary to secure a viable project. (Carolan, 1994.)
An existing EPA initiative to provide technical assistance in access to EPA publications is the Control
Technology Center (CTC). Providing technical support in estimating landfill gas emissions and evaluating
control/utilization options is included in the CTC scope. Currently the CTC is responding to over 2,000
telephone calls per year on landfill gas issues. In addition, the CTC is sponsoring the development of
software for estimating landfill emissions based on a first order decomposition equation. Defaults for
estimating emissions can be based on user supplied information, AP-42 values (U.S. EPA, 1991) for
developing state inventories, or CAA values to determine applicability. The original version of the model
was published in 1990 (Pelt et al., 1990). The updated version is to be released in conjunction with the
promulgation of the CAA landfill rule which is scheduled for June 1995. The CTC may be reached at:
EPA Control Technology Center (CTC)
U.S. Environmental Protection Agency (MD-13)
Research Triangle Park, North Carolina 27711
Hotline: (919) 541-0800, Fax: (919) 541-2157
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2000
750
LFGFLOW(mmscfd)
LEGEND:
mmscfd - million standard cu.ft.7day
scfm - standard cu. fUminute
BOOE - Barrel of Oil Equivalents
PTC - Production Tax Credits
EXAMPLE:
1 mmscfd of LFG @ 50% CK
= 700 scfm of LFG 4
= 350 scfm of CH4
= $190,000 of PTCs in 1994
ASSUMPTIONS:
• 1scfofCfy=1,OOOBtu's
" PTC escalation rate = 4%/year
* Extraction rate constant
365 days/year
METHANE FLOW (scfm)
$6.22
in 1995
$5.75
in 1993
$5.98
in 1994
Figure 12. Chart to calculate production tax credits from landfill gas flow.
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2000
LFG FLOW (mmscfd)
LEGEND:
mmscfd - million standard cu. fUday
scfm - standard cu. ftVminute
EXAMPLE:
1 mmscfd of LFG
= 695 scfm of LFG
= 310 scfm of CH4(% CH*= 45)
= 1.25 to 1.5 MW electricity
(heat rate 15,000 and
12,500 Btu's respectively)
Note: heat rate is the
higher heating value
METHANE FLOW (scfm)
750
Figure 13. Chart to calculate electricity output from landfill gas flow.
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4.2.1 New Initiatives
Control of greenhouse gas emissions (CO2> CH4, and many VOCs) was addressed at the international
environmental conference in Rio de Janeiro in June 1992. At this conference 154 heads of state signed
an international agreement to promote and cooperate in activities that would mitigate future climate change
and its potential impacts. President Clinton's Climate Change Action Plan promotes efficiency and U.S.
ingenuity as the best strategies for confronting the threat of global warming caused by greenhouse gases.
Under the Climate Change Action Plan, the Department of Energy is implementing a research,
development, and demonstration program (RD&D Program) targeted at the technical barriers to landfill CH4
energy recovery. This program will include technology demonstrations and related efforts to speed the
commercialization of new or improved recovery and utilization technologies. This program is to build on
EPA's existing RD&D programs on landfill gas. A collaboration research program is being planned that will
help to achieve near-term reductions of CH4.
Another component of the Climate Change Action Plan is the Landfill Methane Outreach Program of the
EPA. Through this program, EPA is working with landfill owners and operators, states, tribes, utilities, and
other federal agencies to promote the use of landfill gas as an energy resource. The Landfill Methane
Outreach Program is designed to remove regulatory, information, and other barriers by promoting greater
regulatory awareness of project opportunities, furthering understanding of energy benefits, providing
technical information, and fostering common goals. Through the Landfill Methane Outreach Program, EPA
creates alliances with states and utilities to achieve these goals.
Participating states agree to review and explore opportunities to overcome any unnecessary regulatory,
administrative, and other barriers to widespread adoption of energy recovery at landfills. Also, states will
assist in information transfer. Participating utilities agree to cooperate with EPA to develop win/win
strategies for promoting the development of landfill gas resources. They will also assist in the distribution
of outreach materials.
EPA is launching the Landfill Methane Outreach Program in fall, 1994 in five key states. The Program will
expand to an additional ten states in summer 1995 and nationally the following year. More information may
be obtained from:
EPA Landfill Methane Outreach Program
U.S. EPA 6202J, 401 M Street, SW, Washington} DC 20460.
Hotline: 202 233-9042, Fax: 202 233-9569
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5. EMERGING TECHNOLOGIES
Diverse aspects of landfill gas utilization technologies, including pipeline purification and use in boilers,
engines, or turbines, have been discussed before in Chapter 3 of this document as well as in numerous
other publications (see Appendix B: Further Reading). Apart from these established technologies, there
are also emerging landfill gas applications that appear promising for the future. In this chapter, three of
these emerging applications are presented:
• Landfill gas utilization as vehicular fuel (demonstration project, described in Appendix J),
• Conversion of landfill gas to methanol (demonstration plant under construction), and
• Landfill gas utilization in fuel cells (demonstration project).
Other options to make use of landfill gas exist. Two of these, Organic Rankine Cycle converters and
Stirling engines, are worth noting. An Organic Rankine Cycle converter makes use of the waste heat and
is, therefore, not specific to landfill gas applications. Perennial Energy of West Plains, Missouri has
conducted work with Organic Rankine applications on waste heat from landfill gas projects; however, most
of their Organic Rankine experience involves utilization of heat from geothermal sources. The Stirling
engine was invented in 1816 in Scotland. It is an external combustion engine (like a steam engine) that
uses combustion energy to rapidly heat and cool an enclosed gas (e.g., air or hydrogen). The hot
expanding gas propels a piston and shaft. To date no Stirling engines have been field tested for landfill
gas applications.
The three aforementioned technologies have in common the requirement for thorough landfill gas
purification to a grade higher than is necessary for use in boilers or engines. As reported in Table 2, landfill
gas consists of methane, CO2, H2O, H2S, and various trace constituents, including NMOCs. If there is air
intrusion into the landfill, the landfill gas will also contain nitrogen (N2). The effect of these gases (reducing
the heating value and causing corrosion) on equipment performance has been discussed in detail in
previous chapters. Table 3 shows several commercial processes available for purifying gas.
TABLE 4. GAS PURIFICATION METHODS AND PRINCIPLES
Process
Absorption
Adsorption
Membrane separation
Principle
Solubility
Adsorption potentials
Pressure and concentration
Separating
Medium
Liquid
Solid
Membranes
Example
Removal of CO2 and
natural gas
"Drying" of gases
Various applications
H2S from
gradients
Condensation Thermal energy
Chemical Conversion Chemical bonding
Various applications
Reactive chemical Various applications
As most processes are proprietary, little technical information is available. The Selexol™ Process and PSA
are two technologies with merit for the landfill gas industry. Both have been applied to projects with
relatively large gas flows of 85,000 m3 (3x106 scf) per day or greater. For smaller projects, membrane
separation appears to be more suited. Membrane separation may be combined with absorption or other
mechanisms. In selection of the optimum process for producing vehicle-quality fuel, the quality constraints
on the vehicle fuel are most important (EMCON et al., 1981).
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5.1 COMPRESSED LANDFILL METHANE AS VEHICULAR FUEL
Vehicle fueling with compressed gas is of high interest for environmental and other reasons. Technology
for such fueling is well established. In Europe, millions of vehicles, including many passenger cars run on
liquified gas, containing a mixture of methane and higher carbon organic gases. Using landfill gas would
involve purification and compression for reduced volume storage on board of vehicles. The vehicles would
have to be equipped with conversion kits, which include valves, regulators, and safety devices to manage
the high pressures involved.
At the Puente Hills landfill of the Los Angeles County Sanitation District, a membrane separation system
and a landfill gas fueling facility have been installed. A demonstration project is underway to verify the
operational performance of different vehicles running on landfill gas purified to approximately 97 percent
methane. (Details on the Puente Hills vehicular fuel program can be found in Appendix J.) The more .CO2
that can be left in the gas, the easier and more economical processing will be. A vehicle gas engine laid
out for natural gas will perform best if the gas has a higher heating value (HHV) of at least 35.4 MJoule/m3
(950 Btu/ft3). Natural gas has a HHV of 35.4 to 39.1 MJoule/m3 (950 to 1,050 Btu/ft3). If it is assumed that
purified landfill gas has some N2 (which is inert and, therefore, very hard to remove), it becomes necessary
to remove a very large portion of the CO2 to reach a HHV of 950 Btu/ft3 with landfill gas-based methane.
The use of methane as a vehicle fuel usually involves the conversion of a gasoline engine to operate on
both methane and gasoline. The conversion process is relatively simple because no internal modifications
of the engine are required. Conversion equipment generally includes a variable gas-air mixer, which is
incorporated into the carburetor, and a series of regulators and valves which deliver the gas from the
storage tanks. One major drawback of methane fueled vehicles is their short driving range, resulting from
the vehicles limited storage capacity.
5.2 LANDFILL METHANE CONVERSION TO METHANOL
At the BKK landfill in West Covina, California, a plant is being built that is intended to convert landfill
methane into methanol. The project is a joint venture between TerraMeth Industries (TMI), BKK, and the
South Coast Air Quality Management District (SCAQMD) with TMI being the lead partner. TMI is based
in Walnut Creek, California and has developed a technology to convert (waste) methane into methanol.
The project is scheduled for start-up by October 1994.
As a result of Federal and State regulations, methanol is being looked at as (a supplement to) vehicular
fuel, which is cleaner than gasoline. The SCAQMD owns 70 methanol-fueled cars. Also, the methanol
could be used to supplement fuel for garbage trucks. In addition, the methanol may be sold as chemical
feedstock. Apart from the environmental benefits, one important advantage of methanol production is that
the methanol can be stored easily.
The methanol plant at the BKK landfill is laid out for approximately 3.6 mmscfd of landfill gas, containing
52 percent methane and would produce approximately 16,700 gallons per day of grade A methanol.
Process details are proprietary, but the outlines of the methane conversion may be described as follows.
In the gas cleanup phase, water and sulfur are adsorbed and a scrubber and carbon bed further remove
impurities. CO2 is extracted after which the methane is chemically changed into methanol by catalytic
conversion in various process steps. The methanol is purified by distillation and may be stored on site.
43
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5.3 LANDFILL METHANE IN FUEL CELLS
Fuel cells may be compared to large electrical batteries (with ancillary equipment, such as catalysts) and
provide a means to convert the chemical bonding energy of a chemical substance directly into electricity.
A difference between a battery and a fuel cell is that in a battery all reactants are present within the battery
and are slowly being used up with battery utilization (though they can be regenerated in rechargeable
batteries), while in a fuel cell fresh reactants (fuel) are continuously being provided. There are four basic
types of fuel cells, each of which has a unique combination of technical performance characteristics. One
type, the phosphoric acid fuel cell, is ahead of the others in its developmental stage and is commercially
available (Figure 14). It is suitable for utility distributed power use, commercial light industrial use, and
heavy vehicular use. Much research has been done on the generation of electricity with phosphoric acid
fuel cells using natural gas. Inside the phosphoric acid fuel cell, hydrogen obtained from a fuel processor
is converted to water, producing electricity (Figure 15). The other types of fuel cells (e.g., molten
carbonate) are in varying stages of development and demonstration and may be ready for the market in
a decade or two (Arthur D. Little, Inc., 1993).
The EPA initiated a research and development project in 1991 to evaluate the use of commercially
available fuel cells for landfill gas applications, because of the potential environmental and energy efficiency
characteristics, which include:
• Higher energy efficiency than conventional technologies in use (fuel cells can achieve 40
percent energy efficiency),
• Minimal by-product emissions which can be a critical consideration in ozone, NOX and CO
nonattainment areas,
• Ability to operate in remote areas,
• Minimal labor and maintenance,
• Minimal noise impact (i.e., there are no moving parts), and
• Availability to smaller as well as larger landfills (available in 200 kW modules).
The major technical consideration associated with the application of fuel cells to landfill gas projects is the
gas clean-up system. Testing of the EPA clean-up system has just been completed resulting in over
200 hours of successful operation. The gas cleanup system is designed to clean the gas to 3 ppmv of
chlorides and 3 ppmv of sulfur. Next, a 1-year demonstration is planned to study the performance of fuel
cells for landfill gas energy conversion applications (Sandelli, 1992).
The principal non-technical consideration associated with fuel cells has been the capital cost. The
manufacturer of the phosphoric acid fuel cell, International Fuel Cells subsidiary ONSI, has guaranteed the
capital cost for the new advanced power module to be $3,000 per kilowatt (kW) for delivery in 1995, and
plans to have the cost at $1,500 per kW by 1998. Costs for 1C engine plants currently are between $950
to $1,250 per kW.
44
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NATURAL
GAS ; W-:•. :| PROCESSOR
Figure 14. Fuel cell.
Anode
H2,C02|
CO '
Hj —«- 2H+ + 2e~
400° F
Acid
electrolyte
H3P04
(Matrix)
J_£
/2
Cathode
Air
2e
• Operates on hydrogen obtained from fuel processor
• Operates on untreated air
• Water formed as vapor
Figure 15. Chemical reactions in a phosphoric acid fuel cell.
45
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6. INDEX
Blower 14
Boiler 27
Buildups 10
Carbon steel 14
Carburetion 18
Climate Change Action Plan 41
Coalescing filter 17
Compressor 14
Condensate 10, 15
Condensate traps 15
Control of greenhouse gas emissions
(Global warming) : 41
Control Technology Center (CTC)
(EPA's information transfer center) 38
Corrosion 15
Crankcase ventilation 17
Deposits . . 10, 22
Desiccant 16
Detonation-sensitive control 19
Dimethyl siloxane 10
Dioxins 11
Dowtherm™ 28
Environmental externalities 31
Exhaust gas 15
Federal Energy Regulatory Commission 34
Filtration 10, 17
Flame front propagation 27
Flameouts . 28
Flow measurements . . .' 12
Fuel-air ratio 18
Furans 11
Gas composition measurements 12
Gas generation rate 11
Gemini™ 29
Halocarbons 9
Ignition timing adjustment 19
Interconnect 34
Intervals between oil changes 23
Knockout tank 16
Kryosol™ 29
Landfill Methane Outreach Program 41
Microbial decomposition 1
Misfiring 21
Natural gas supplementation 20
Nitrogen oxides 17
Nonmethane organic compounds
(NMOCs) 9
Oil ash 22
Oil change intervals 22
Oil Selection 17
46
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Particulates 10
PCB 11
Pipeline gas 2, 9
Pilot tube 12
Pressure-swing absorption 29
Production Tax Credit 37
Public Utility Commission 31
RD&D Program
(Department of Energy's incentive program) 41
Refrigeration and Drying 16
Selexol™ 16,29
Siloxane deposits . 10
Slugs t 10
Temperature topping ' 24
Total base number (TBN) 17
Turbocharging 19
47
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7. REFERENCES
Augenstein, D. and J. Pacey. 1992. Landfill Gas Energy Utilization: Technology Options and Case Studies.
U.S. EPA/AEERL, Research Triangle Park, NC. EPA-600/R-92-116 (NTIS PB92-203116).
Augenstein, D. and J. Pacey. 1991. Landfill Methane Models. Proceedings from the Technical Sessions of
SWANA's 29th Annual Int. Solid Waste Exposition, Cincinnati, OH. SWANA, Silver Spring, MD, 1991
Arthur D. Little, Inc. 1993. The Role of Fuel Cell Technology in the International Power Equipment Market-
Policy/Strategy Issues. Prepared for The World Fuel Cell Council, Frankfurt, Germany. Arthur D. Little, Inc.
Cambridge, MA.
California Integrated Waste Management Board. 1989. Procedural Guidance Manual for Sanitary Landfills.
Volume II. Landfill Gas Monitoring and Control Systems. California Integrated Waste Management Board.
Sacramento, CA.
Carolan, M. 1994. "Should Landfill Owners Pay Developers of Landfill Gas to Energy Projects?" Proceedings
from the 17th Annual International Landfill Gas Symposium. SWANA, Long Beach, CA.
Chadwick, C. 1990. Reduced Power Requirements of Low Pressure Gas Reciprocating Engines. Proceedings
from the GRCDA 13th Annual Int. Landfill Gas Symposium. SWANA, Silver Spring, MD.
Doom, M.R.J., L.A. Stefanski, and M.A. Barlaz, 1994. Estimate of Methane Emissions from U.S. Landfills.
U.S. EPA/AEERL, Research Triangle Park, NC. EPA-600/R-94-166 (NTIS PB94-213519).
EMCON Associates. 1982. Methane Generation and Recovery from Landfills. Second Edition, Ann Arbor
Science. Ann Arbor, Ml.
EMCON Associates, CAL RECOVERY SYSTEMS, INC., and GAS RECOVERY SYSTEMS, INC. 1981.
Feasibility Study: Utilization of Landfill Gas for a Vehicle Fuel System. Department of Energy.
Document No. DE-83010622. January 1981.
Eppich, J., J. Cosulich, and H.H. Wong. 1990. Puente Hills Energy Recovery from (PERG) Facility. Presented
at the First United States Conference on Municipal Solid Wastes Solution for the 90's. Sponsored by the U.S.
EPA. Washington DC. June 13-16, 1990.
Eppich, J.D. and J.P. Cosulich. 1993. Collecting and Using Landfill Gas as a Boiler Fuel. Solid Waste & Power.
July/August 1993. pp. 27-34.
Gas Engineer's Handbook. 1965. Industrial Press, New York.
Gullett, B.K., P.M. Lemieux, and J.E. Dunn. 1994. Role of Combustion and Sorbent Parameters in Prevention
of Polychlorinated Dibenzo-p-dioxin and Polychlorinated Dibenzofuran Formation during Waste Combustion.
Environmental Science & Technology, Vol. 28, 1994.
Held, W.M. and P.S. Woodfill. 1989. Piping Materials Used in Landfill Gas Collection Systems—A Review and
History. Proceedings from the GRCDA 13th Annual International Landfill Gas Symposium. SWANA, Silver
Spring, MD.
Hernandez, R.J. 1989. Selexol Solvent Process: Ten Years of Experience in L.F.G. Treatment. IGT (Institute
of Gas Technology) Symposium on Fuels from Biomass. IGT, Chicago, IL. 1989.
Kleinfelder, Inc. 1991. Source Test Report Boiler and Flare Systems. Prepared for Laidlaw Gas Recovery
Systems, Coyote Canyon Landfill, Irvine, CA. Prepared by Kleinfelder, Inc. Diamond Bar, CA.
48
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REFERENCES (continued)
Koch, W.R. 1986. A New Process for the Production of High-Btu Gas. Proceedings from the GRCDA 9th
International Landfill Gas Symposium. SWANA, Silver Spring, MD.
Markbreiter, J. 1983. Kryos Process for Pipeline Methane Purification. GRCDA Annual Landfill Gas
Symposium. SWANA, Silver Spring, MD.
Markham, M. 1992. Landfill Gas Recovery to Electric Energy Equipment: Waste Management's 1991
Performance Record. SWANA's 15th Annual Landfill Gas Symposium. SWANA, Silver Spring, MD.
Maxwell, G. 1989. Reduced NOX Emissions from Waste Management's Landfill Gas Solar Centaur Turbines.
Proceedings Air and Waste Management Association's 82nd Annual Meeting, Anaheim, CA. June 1989.
Millican, R.W. South Coast Air Quality Management District 1994. Test Summaries of Source Tests Conducted
on Landfill Gas Fired Equipment in the South Coast Area. Correspondence between R.W. Millican and S.
Thprneloe, US/EPA, AEERL, Research Triangle Park, NC.
Moilanen, G.L. 1986. Engineering Report Puente Hills Landfill Flare #11: Dioxin, Furan, and PCB Test Results.
Report No. Sierra 86021-100. Prepared for County Sanitation Districts of Los Angeles County, Whittier, Ca.
Prepared by Sierra Environmental Engineering.
Moss, H.D.T. 1991. The Use of Landfill Gas in Reciprocating Engines. Proceedings of Third International
Landfill Symposium, Sardinia, Italy. October 14-18, 1991.
Pape & Steiner Environmental Services. 1990. Compliance Testing for Spadra Landfill Gas-to-Energy Plant.
Prepared for Ebasco Contractors. Report PS-90-2315/Project 6908-90.
Pelt, W.R., R.L. Bass, I.R. Kuo, and A.L Blackard. 1990. Landfill Air Emissions Estimation Model — User
Friendly Computer Software and User's Manual. EPA-600/8-90-085a,b (NTIS PB91 -167718 and PB91 -507541).
Sandelli, G.J. 1992. Demonstration of Fuel Cells to Recover Energy from Landfill Gas.. Phase I. Final Report:
Conceptual Study. EPA-600-R-92-007 (NTIS PB92-137520).
Schlotthauer, M. 1991. Gas Conditioning Key to Success in Turbine Combustion Systems Using Landfill Gas
Fuels. Proceedings of the GRCDA/SWANA 14th International Annual Landfill Gas Symposium. SWANA. Silver
Spring, MD.
Shah, V. 1990. Landfill Gas to High Btu Sales Gas Using Selexol™ Solvent Process. Proceedings from the
GRCDA 13th Annual International Landfill Gas Symposium, SWANA, Silver Spring, MD.
Thomeloe, S. A. and J. G. Pacey. 1994. Landfill Gas Utilization—Database of North American Projects.
Proceedings from the 17th Annual International Landfill Gas Symposium. SWANA, Long Beach, CA.
U.K. Department of Energy. 1992. Power Generation from Landfill Gas. United Kingdom Department of Energy,
Harwell Laboratories, Oxfordshire.
U.S. Environmental Protection Agency. 1991. Compilation of Air Pollutant Emission Factors. Fourth Edition
(AP-42). Research Triangle Park, NC. September 1991.
Vogt, W.G. and J.L. Briggs. 1989. Disposal Options for Landfill Gas Condensate. Proceedings from the 12th
Annual International Landfill Gas Symposium. SWANA, Silver Spring, MD.
Watson, J.R. 1990. Pretreatment of Landfill Gas. Proceedings from the GRCDA 13th Annual International
• Landfill Gas Symposium. SWANA, Silver Spring, MD.
49
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APPENDIX A: ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY
UTILIZATION: TECHNOLOGY OPTIONS AND CASE STUDIES
Augenstein, D. and J. Pacey. 1992.
Developed for the Air & Energy Engineering Research Laboratory,
Office of Research and Development, U.S. EPA,
Research Triangle Park, North Carolina
Publication number: EPA-600/R-92-116
(NTISPB92-203116)
For all international requests, contact: INFOTERRA/USA at (202) 260-5917 by phone or
(202) 260-3923 by fax. All other requestors should either contact the National Technical Information
System at (703) 487-4650 (phone) or (703) 321-8547 (fax) or the EPA Control Technology Center
Hotline at (919) 541-0800 (phone) or (919) 541-2157 (fax).
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APPENDIX A- ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY UTILIZATION: TECHNOLOGY
OPTIONS AND CASE STUDIES (continued)
ABSTRACT
Combustible, methane-containing gas from refuse decomposing in landfills, or "landfill gas," can be fuel
for a variety of energy applications. This report presents case studies of projects in the United States
where it has been used for energy. It also presents overviews of some of the important issues regarding
landfill gas energy uses, including appropriate equipment, costs and benefits, environmental concerns,
and obstacles and problems of such energy uses.
With allowance for its properties, landfill gas can be used in much commercially available equipment that
normally uses more conventional fuels such as pipeline natural gas. This includes equipment for space
heating, boilers, process heat provision and electric power generation. Landfill gas energy uses, already
significant, could increase based on estimates of the landfill gas that could be recovered, and providing
that other factors, particularly economic ones, are favorable. Such energy uses have environmental and
conservation benefits.
Factors to be considered in using landfill gas for energy include contaminants, which can corrode
equipment and cause other problems, and its lower energy content, resulting in moderate equipment
derating. Other issues that are of normal concern for landfill gas, such as forecasting its recoverable
quantity over time, and its efficient collection, also bear importantly on its use for energy.
The case studies review landfill gas energy use at six sites in the U.S. The energy applications include
electric power generation by reciprocating internal combustion engines, electric power generation by gas
turbine, space heating, and steam generation in a large industrial boiler. Case study applications are
considered to represent attractive candidate uses for implementation at additional U.S. landfill sites. The
case studies present the relevant site features, background regarding the development of the case study
project, equipment used, operating experience, economics, and future plans at the sites. Obstacles and
problems at the sites are discussed. The case study sites exhibit wide variation in features such as cost
and degree of operating difficulty experienced. Such variation is typical of landfill gas energy projects,
which tend to be site specific. Literature containing information on other relevant case studies, in both the
U.S. and other countries, is also referenced.
Important conclusions include
• Landfill gas can be a satisfactory fuel for a wide variety of applications. Such uses
have environmental and conservation benefits. Many types of energy equipment
designed for "conventional" fuels can operate on landfill gas with outputs reduced by
about 5 to 20 percent.
• Allowances must be made for the unique properties of landfill gas and particularly its
contaminants. Pitfalls possible in landfill gas energy applications include equipment
damage due to such gas contaminants, and shortages resulting from over-estimation
of its availability.
• The degree of gas cleanup and the methods used vary widely; the necessary amount
of cleanup and the optimum tradeoffs between cleanup stringency and the frequency
of maintenance steps (such as oil changes) are not well established.
• Cost-to-benefit ratios can vary widely; at some sites they are excellent, while at others
they are a major limiting factor. Economics are probably the most important factor
limiting landfill gas energy uses. Economics currently tend to preclude smaller scale
uses, uses where electric power sale prices are low, and uses at remote sites lacking
convenient energy applications or outlets. Much of the landfill gas generated today is
not used for energy because of economics.
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APPENDIX A: ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY UTILIZATION: TECHNOLOGY
OPTIONS AND CASE STUDIES (continued)
• Energy equipment emission limits in some U.S. locations may also restrict landfill gas
energy use, despite an environmental balance sheet that generally appears to be
positive.
This report identifies technical areas where energy uses are likely to benefit from improvements. Some of
these are alluded to above. This report also comments briefly on incentive, barrier elimination, and other
approaches that may facilitate landfill gas use. Finally, for present and future landfill gas users, further
detailed documentation of the problems experienced, and the results of approaches to them (both
successful and unsuccessful), would be very helpful.
This report was submitted by EMCON Associates, in fulfillment of subcontract 275-026-31-05 from
Radian Corporation, as well as subcontract 93.3 from E.H. Pechan and Associates, and performed under
the overall sponsorship and direction of the U.S. Environmental Protection Agency, Global Emissions and
Control Division. This report covers a period from February 1991 to January 1992, and work was
completed as of February 1992.
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APPENDIX A: ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY UTILIZATION: TECHNOLOGY
OPTIONS AND CASE STUDIES (continued)
CONTENTS
FOREWORD II
ABSTRACT JII
ACKNOWLEDGEMENTS . jell
CONVERSIONS Xlv
1: INTRODUCTION AND BACKGROUND 1
1.1 Landfills and Landfill Gas: General. . . ; .1
1.2 Composition of Landfill Gas 2
1.3 Estimating the Gas Recoverable for Energy Uses 3
1.4 Gas Extraction Systems •: 3
1.5 Environmental and Conservation Aspects of Landfill
Gas Energy Use 4
1.6 Regulatory Issues , 4
2. USE OF LANDFILL GAS AS A FUEL—TECHNICAL ISSUES 5
2.1 Gas Composition Analysis 5
2.2 Corrosion Effects . .• 5
2.3 Particulates and Their Effects 6
2.4 Gas Cleanup 6
2.5 Dilution and Other Performance Reduction Effects
With Landfill Gas 7
2.6 Load Factor ("Use it or lose it") 8
3. ENERGY APPLICATIONS AND EQUIPMENT 9
3.1 Current Applications and Equipment. . . 9
3.1.1 Space heating (and cooling) . .9
3.1.2 Process heating and cofiring applications 10
3.1.3 Boiler fuel 10
3.1.4 Reciprocating internal combustion engines with
electric power generation 10
. 3.1.5 Gas turbines 11
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APPENDIX A: ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY UTILIZATION: TECHNOLOGY
OPTIONS AND CASE STUDIES (continued)
CONTENTS
3.1.6 Steam-electric 12
3.1.7 Purification to pipeline quality methane 12
3.2 Potential Future Technologies 12
3.2.1 Fuel cells 12
3.2.2 Compressed gas vehicle fuels 13
3.2.3 Synthetic liquid fuels and chemicals . 13
4. COST AND REVENUE COMPONENTS 14
4.1 Components of Cost and Income .14
4.2 Cost Data: Examples 15
4.2.1 Hypothetical generating facility example:
Cost component ranges T5
4.2.2 Reported electric facility capital costs:
GAA Yearbook 15
4.3 Other Economic Issues 17
4.3.1 Revenue requirement for electric power
generation 17
4.3.2 Initial cost estimating 17
4.3.3 Economic impediments to energy applications 17
5. Case Studies 19
5.1 Electric Power Generation and Space Heating Using
Landfill Gas: Prince George's County, Maryland 19
5.1.1 Introduction and general overview . . . 19
5.1.2 History of project implementation 19
5.1.3 Landfill and landfill gas system. . 23
5.1.4 Energy facility and equipment 23
5.1.5 Environmental/emissions 27
5.1.6 Operation and maintenance 27
5.1.7 Economics 28
5.1.8 Discussion 29
5.1.9 Calculation bases—energy use and financing . 30
5.2 Electricity Generation Using Cooper-Superior Engine
at the Otay Landfill 31
5.2.1 Introduction and general overview 31
5.2.2 Otay landfill and landfill gas system 31
, 5.2.3 Gas preprocessing and energy plant equipment 33
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APPENDIX A: ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY UTILIZATION: TECHNOLOGY
OPTIONS AND CASE STUDIES (continued)
CONTENTS
5.2.4 Environmental/emissions 36
5.2.5 Operation and maintenance 36
5.2.6 Revenue and cost items 37
5.2.7 Discussion 37
5.3 Electric Power Generation Using Waukesha Engines at the Marina Landfill. . 38
5.3.1 Introduction and general overview 38
5.3.2 History of project 40
5.3.3 Landfill and landfill gas extraction system 41
5.3.4 Gas preprocessing and energy plant equipment 43
5.3.5 Environmental/emissions .46
5.3.6 Economics 47
5.3.7 Operation and maintenance 48
5.3.8 Discussion 48
5.4 Electric Power Generation Using Gas Turbines at Sycamore Canyon Landfill. 49
5.4.1 Introduction and general overview 49
5.4.2 History of system implementation 51
5.4.3 Landfill and landfill gas system 51
5.4.4 Plant equipment: Gas preprocessing and energy 52
5.4.5 Environmental 55
5.4.6 Economics 55
5.4.7 Operation and maintenance 56
5.4.8 Discussion : 56
5.5 Landfill Gas Fueled Boiler: Raleigh, North Carolina 57
5.5.1 Introduction and general overview 57
5.5.2 History of project implementation . 57
5.5.3 Landfill and landfill gas system 59
5.5.4 Energy equipment: Blower station, pipeline
and boiler 60
5.5.5 Performance 61
5.5.6 Emissions 62
5.5.7 Operation and maintenance 62
5.5.8 Economics 63
5.5.9 Discussion 63
5.6 Electrical Power Generation Using Caterpillar Engines at
the Central Landfill, Yolo County. California 63
5.6.1 Introduction and general overview 63
5.6.2 History of project implementation 65
5.6.3 Landfill and landfill gas extraction system 66
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APPENDIX A: ABSTRACT AND TABLE OF CONTENTS OF LANDFILL GAS ENERGY UTILIZATION: TECHNOLOGY
OPTIONS AND CASE STUDIES (continued)
CONTENTS
5.6.4 Gas preprocessing and energy conversion equipment 68
5.6.5 Performance and availability issues 69
5.6.6 Environmental/emissions .71
5.6.7 Operation and maintenance 71
5.6.8 Economics 71
5.6.9 Discussion '. 71
5.7 Other Relevant Case Studies and Information'. 72
5.8 Other Supplemental Literature 75
6. REVIEW, COMMENTARY, AND CONCLUSIONS 76
6.1 Conclusions 76
6.2 Further Needs 77
6.3 Facilitating Landfill Gas Energy Use 77
REFERENCES .79
Appendices
Appendix A Estimating Gas Availability for Energy Uses A-1
Appendix B Gas Extraction Systems B-1
Appendix C Comments on Environmental and Conservation
Aspects of Landfill Gas Energy Use C-1
Appendix D Regulatory Issues with Landfill Gas Use D-1
Appendix E Gas Composition Analysis E-1
Appendix F Cost, Revenue, and Other Economic Components F-1
Appendix G Site Plan, Otay Electrical Generation Facility G-1
Appendix H Equipment Specifications, Otay Generation Facility H-1
Appendix I PG&E Power Purchase Rates, Marina 1-1
Appendix J Cleaver-Brooks Boiler Specifications J-1
Appendix K United Kingdom Case Studies K-1
Appendix L The Economics of Landfill Gas Projects in the
United States L-1
Appendix M Waste Management of North America, Inc.
Landfill Gas Recovery Projects M-1
Appendix N I-95 Landfill Gas to Electricity Project Utilizing
Caterpillar 3516 Engines N-1
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APPENDIX B: FURTHER READING
A large body of literature discusses the generation, recovery and energy uses of landfill gas, as well as
other aspects of its technology. References are listed by general category of information that may be of
interest.
Information on Environmental Protection Agency(EPA) publications:
EPA documents may be ordered prepaid from National Technical Information System at (703) 487-
4650 (phone) or (703) 321-8547 (fax). Specific requests for information may be made throught the
EPA Control Technology Center Hotline at (919) 541-0800 (phone) or (919) 541-2157.
For international requests contact: INFOTERRA/USA at (202) 260-5917 (phone) or (202) 260-
3923 (fax).
EPA Landfill Methane Outreach Program:
EPA Landfill Methane Outreach Program
U.S. EPA 6202J, 401 M Street, SW, Washington! DC 20460.
Hotline: 202 233-9042, Fax: 202 233-9569
Solid Waste Association of North America (SWANA)
In 1994, SWANA's Annual Landfill Gas Symposium was organized for the 17th time. Proceedings
of these symposia may be recommended for further reading. SWANA can be reached at: (301)
585-2898.
1. GENERAL INFORMATION ON LANDFILL GAS AND ITS CONTROL/UTILIZATION
OPTIONS.
Augenstein, D. and J. Pacey. Landfill Gas Energy Utilization: Technology Options and Case Studies.
U.S. EPA/AEERL, Research Triangle Park, NC. EPA-600/R-92-116 (NTIS PB-92-203116). 1992.
EMCON Associates. Methane Generation and Recovery From Landfills. Second Edition, Ann Arbor
Science. Ann Arbor, Ml. 1982.
Gendebien, A., M. Pauwels, M. Constant, M.J. Ledrut-Damanet, E.J. Nyns, H.C. Willumsen, J. Butson, R.
Fabry, and G.L. Ferrero. Landfill Gas From Environment to Energy. Directorate-General for Energy,
Commission of the European Communities, Brussels, EUR 14017/1 EN. 1992.
Gronow, J.R. The Department of the Environment Landfill Gas Programme. U.K. Department of Energy
and Department of the Environment. Landfill Gas: Energy and Environment '90. Bournemouth, United
Kingdom. 1990.
Lawson, P.S. The Department of Energy Landfill Gas R&D Programme. U.K. Department of Energy and
Department of the Environment. Landfill Gas: Energy and Environment '90. Bournemouth, United
Kingdom. 1990.
Public Technology, Inc. Landfill Methane Gas Recovery and Utilization: A Handbook for Local
Governments. Public Technology, Inc., Washington, DC. 1994.
U.K. Department of Energy. Harwell Laboratories, Oxfordshire. Landfill Gas and Anaerobic Digestion of
Solid Waste. London, United Kingdom. London, United Kingdom. 1988.
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Willumsen, H.C. The Problematics of Landfill Gas Technology. Proceedings of Sardinia '91 - Third
International Landfill Symposium. Sardinia, Italy. 1991.
2. SITE-SPECIFIC MODELING AND FIELD TESTING.
Augenstein, D. Landfill Methane Enhancement. Proceedings of the 16th Annual Landfill Gas
Symposium. SWANA, Louisville, KY. March 1993.
Augenstein, D. and J. Pacey. Landfill Methane Models. Proceedings from the Technical Sessions of
SWANA's 29th Annual International Solid Waste Exposition. Cincinnati '91. SWANA, Silver Spring, MD.
September 1991.
Augenstein, D. and J. Pacey (USA). Modeling Landfill Methane Generation. Proceedings of Sardinia '91
- Third International Landfill Symposium. Sardinia, Italy. 1991.
Biezer, M.B., T.D. Wright, and D.E. Weaver. 1985. A Field Test Program for Determining Landfill Gas
Recovery Feasibility. Proceedings of the 8th International Landfill Gas Symposium. GRCDA/SWANA,
Silver Spring, MD. 1985.
Campbell, D.J.V. and S.C. Croft. Landfill Gas Enhancement: Brogborough Test Cell Programme. U.K.
Department of Energy and Department of the Environment. Landfill Gas: Energy and Environment '90.
London, United Kingdom. 1990.
Ehrig, H.J. (D). Prediction of Gas Production from Laboratory Scale Tests. Proceedings of Sardinia '91 -
Third International Landfill Symposium. Sardinia, Italy. 1991.
EMCON Associates. Methane Generation and Recovery From Landfills. Second Edition. Ann Arbor
Science. Ann Arbor, Ml. 1982.
Manley, B.J.W., R.G. Gregory, and N. Gardener. An Assessment of the U.K. Landfill Gas Resource.
U.K. Department of Energy and Department of the Environment. Landfill Gas: Energy and Environment
'90. London, United Kingdom. 1990.
Manley, B.F.W., R.G. Gregory, and N. Gardner. Assessment of Landfill Gas Production for the U.K.
Proceedings of Sardinia '91 - Third International Landfill Symposium. Sardinia, Italy. 1991.
Nilsson, P. and S. Edner (SW). Test Cell Study of Methane Production. Proceedings of Sardinia '91 -
Third International Landfill Symposium. Sardinia, Italy. 1991.
Pacey, J. and D. Augenstein. Modelling Landfill Methane Generation. U.K. Department of Energy and
Department of the Environment. Landfill Gas: Energy and Environment '90. London, United Kingdom.
1990.
Pelt, W.R., R.L. Bass, I.R. Kuo, and A.L. Blackard. Landfill Air Emissions Estimation Model — User
Friendly Computer Software and User's Manual. EPA-600/8-90-085a,b (NTIS PB91-167718 and PB91-
507541). December 1990.
U.S. EPA. Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed
Standards and Guidelines. Office of Air Quality Planning and Standards, U.S. Environmental Protection
Agency, Research Triangle Park, NC. March 1991. EPA-450/3-90-011a (NTIS PB91-197061).
Van Heuit, R. and J. Pacey. The Gas Field Test: Design. Installation and Maintenance. Proceedings of
the Annual International Solid Waste Symposium. GRCDA/SWANA, Silver Spring, MD. 1987.
Van Heuit, R. Estimating Landfill Gas Yields. Proceedings of the GRCDA's 9th Annual International
Landfill Gas Symposium. GRCDA/SWANA, Silver Spring, MD. 1986.
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Westlake, K. Landfill Microbiology. U.K. Department of Energy and Department of the Environment.
Landfill Gas: Energy and Environment'90. Bournemouth, United Kingdom. 1990.
Zison, S. Landfill Gas Production Curves: Myth vs. Reality. Presentation at SWANA Annual Meeting.
Vancouver, B.C.; SWANA, Silver Spring, MD. 1990.
3. INFORMATION ON EXTRACTION/RECOVERY SYSTEMS.
Echols, R.L. Landfill Gas Recovery Systems. Presented at American Society of Civil Engineers,
National Meeting, NY. September 1992.
EMCON Associates. Methane Generation and Recovery From Landfills. Second Edition. Ann Arbor
Science. Ann Arbor, Ml. 1982.
Leach, A. Landfill Gas Abstraction. U.K. Department of Energy and Department of the Environment.
Landfill Gas: Energy and Environment'90. Bournemouth, United Kingdom. 1990.
Nardelli, R. The Wide World of Landfill Gas Flares. Proceedings of the 16th Annual Landfill Gas
Symposium. SWANA, Louisville, KY. March 1993.
Poland, R.J. Collection Systems for Landfill Gas Recovery and Control — One Size May Not Fit AH.
Submitted Papers and Abstracts for the 10th International Landfill Gas Symposium. GRCDA/SWANA,
Silver Spring, MD. 1987.
U.K. Department of Trade and Industry and Department of Environment. Guidelines for the Safe
Control and Utilisation of Landfill Gas. ETSU B 1296-P1. DOE Report CWM067A/92. Produced by
Environmental Resources Limited, Northampton, U.K. 1993.
4. ENERGY USES.
Anderson, C.E. Owner/Operator Experiences in Developing Electric Utility Contracts and Interconnects.
Proceedings of the 13th Annual International Landfill Gas Symposium. GRCDA, Lincolnshire, IL.
March 1990.
Augenstein, D. and J. Pacey. Landfill Gas Energy Utilization: Technology Options and Case Studies.
U.S. EPA./AEERL, Research Triangle Park, NC. EPA-600/R-92-116 (NTIS PB92-203116). 1992.
Carolan, M.J. Should Landfill Owners Pay Developers of Landfill Gas to Energy Projects? Proceedings
of the 32nd Annual International Solid Waste Exposition. SWANA, San Antonio, TX. August 1994.
Carrico, P.J. Landfill Gas Management Systems: Landfill End Use Impacts. Proceedings of the 17th
Annual Landfill Gas Symposium. SWANA, Long Beach, CA. March 1994.
Castillo, F. Economically Feasible Methods of Landfill Gas Energy Recovery: Brown Station Road
Landfill Recovery Project. Proceedings of the 15th Annual Landfill Gas Symposium. SWANA, Silver
Spring, MD. March 1992.
Davies, G. A Small-Scale Gas Utilisation Scheme. U.K. Department of Energy and Department of the
Environment. Landfill Gas: Energy and Environment'90. London, United Kingdom. 1990.
Freemon, J.P. Landfill Gas Recovery Projects of the County Sanitation Districts of Los Angeles County.
Proceedings of the 12th Annual International Landfill Gas Symposium. GRCDA, Silver Spring, MD.
1989.
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Gendebien, A. M. Pauwels, M. Constant, H.C. Willumsen, J. Buston, R. Fabry, G.F. Ferrero, and
E.J. Nyns. Landfill Gas: From Environment to Energy. State-of-the-Art in the European Community
Context. Proceedings'of Sardinia'91 - Third Internationa! Landfill Symposium. Sardinia, Italy. 1991.
Gordon, J. Landfill Gas Recovery: Achieving the Proper Financing Structure. Proceedings of the 15th
Annual Landfill Gas Symposium. SWANA, Silver Spring, MD. March 1992.
Greenberg, F.L. Selling Electricity to Utilities. Proceedings of the 13th Annual International Landfill Gas
Symposium. GRCDA, Lincolnshire, IL. March 1990.
Haviland, T. Designing a Compressor/Dehydration System to Deliver Landfill Gas. Proceedings of the
13th Annual International Landfill Gas Symposium. GRCDA, Lincolnshire, IL. March 1990.
Jacobs, Cindy. EPA Landfill Methane Outreach Program. Proceedings of the 17th Annual International
Landfill Gas Symposium. SWANA, Long Beach, CA. March 1994.
Jahsen, G.R. The Economics of Landfill Gas Projects in the United States. Presentation in Melbourne,
Australia. February 27, 1992.
Jansen, G.R. The Economics of Landfill Gas Projects. Proceedings of the 9th International Landfill
Gas Symposium. GRCDA, Silver Spring, MD. 1986.
Limbrick, A.J. A Commercial View of Electricity Generation from Landfill Gas. U.K. Department of
Energy and Department of the Environment. Landfill Gas: Energy and Environment '90.
Bournemouth, United Kingdom. 1990.
Mandeville, R.T. Landfill Gas: Energy and Environmental Issues in the USA. U.K. Department of
Energy and Department of the Environment. Landfill Gas: Energy and Environment '90.
Bournemouth, United Kingdom. 1990.
Markham, M.A. Landfill Gas Recovery Projects. Proceedings of the 15th Annual Landfill Gas
Symposium. SWANA, Silver Spring, MD. March 1992.
Maunder, D. Using Landfill Gas in the U.K. Proceedings of the 15th Annual Landfill Gas Symposium.
SWANA, Silver Spring, MD. March 1992.
Monteiro, J.H. Penigo (BR). Landfill Gas Recovery — An Important Energy Resource for Developing
Countries. Proceedings of Sardinia '91 - Third International Landfill Symposium. Sardinia, Italy. 1991.
Nyns, E.J. Landfill Gas: From Environment to Energy in the European Community. Proceedings of
the 15th Annual Landfill Gas Symposium. SWANA, Silver Spring, MD. March 1992.
Pacey, J.G., M.R.J. Doom, and S.A. Thorneloe. Landfill Gas Energy Utilization — Technical and Non-
Technical Considerations. Proceedings of the 17th Annual International Landfill Gas Symposium.
SWANA, Long Beach, CA. March 1994.
Parry, C.G. Gas Quality for Landfill Gas Engines. U.K. Department of Energy. Power Generation from
Landfill Gas. London, United Kingdom. November 1991.
Pierce, J. Alternative Contractual and Financial Arrangements for Implementation of Landfill Gas Power
Generation Projects. Proceedings of the 15th Annual Landfill Gas Symposium. SWANA, Silver Spring,
MD. March 1992.
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Richards, K.M. and E.M. Aitchison. Landfill Gas: Energy and Environmental Themes. U.K.
Department of Energy and Department of the Environment. Landfill Gas: Energy and Environment '90.
Bournemouth, United Kingdom. 1990.
Richards, K.M. The U.K. Landfill Gas and MSW Industry So Far. So Good? U.K. Department of
Energy. Landfill Gas and Anaerobic Digestion of Solid Waste. London, United Kingdom. 1988.
Robinson, M.G. Landfill Gas: Its use as a Fuel for Process Firing and Power Generation. U.K.
Department of Energy and Department of the Environment. Landfill Gas: Energy and Environment '90.
Bournemouth, United Kingdom. 1990.
Scheepers, M.J.J. Landfill Gas in the Dutch Perspective. Proceedings of Sardinia '91 - Third
International Landfill Symposium. Sardinia, Italy. 1991.
Scheepers, M.J.J. Landfill Gas in the Dutch Perspective. U.K. Department of Energy and Department
of the Environment. Landfill Gas: Energy and Environment'90. Bournemouth, United Kingdom. 1990.
Sleeker, P.P. and M.A. Marsden. Comprehensive Landfill Gas Control and Recovery at Outagamie
County. Wisconsin. Landfill. Proceedings of the 13th Annual International Landfill Gas Symposium.
GRCDA, Lincolnshire, IL. March 1990.
Thorneloe, S.A. Landfill Gas Recovery/Utilization — Options and Economics. 16th Annual Conference
on Energy from Biomass and Wastes. Institute of Gas Technology. Orlando, FL. March, 1992.
Thorneloe, S.A. and J. Pacey. Landfill Gas Utilization — Database of North American Projects.
Proceedings of the 17th Annual International Landfill Gas Symposium. SWANA, Long Beach, CA.
March 1994.
Turner, R. Expertise with Landfill Gas Projects: The Development of a Small Scale Power Station.
U.K. Department of Energy. Power Generation from Landfill Gas. London, United Kingdom.
November 1991.
Watson, J.R. Pretreatment of Landfill Gas. Proceedings of the 13th Annual International Landfill Gas
Symposium. GRCDA, Lincolnshire, IL. March 1990.
Wehran, Jr., F.L. Using Landfill Gas to Evaporate Leachate. Proceedings of the 32nd Annual
International Solid Waste Exposition. SWANA, San Antonio, TX. August 1994.
Willumsen, H.C. Danish Status for Landfill Gas Plant. Proceedings of the 16th Annual Landfill Gas
Symposium. SWANA, Louisville, KY. March 1993.
Willumsen, H.C. and L. Bach. Landfill Gas Utilization Overview. Proceedings of Sardinia '91 - Third
International Landfill Symposium. Sardinia, Italy. 1991.
4.1 DIRECT USE - BOILERS AND KILNS
Bier, J.D. Effects of Landfill Gas Management at the Industry Hills Recreation and Conference Center.
Proceedings of the 17th Annual Landfill Gas Symposium. SWANA, Long Beach, CA. March 1994.
Eppich, J.D. and J.P. Cosulich. Collecting and Using Landfill Gas as a Boiler Fuel. Solid Waste &
Power, pp. 27-34. July/August 1993.
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4.2 ELECTRICITY
Anderson, C.E. Selecting Electrical Generating Equipment for Use with Landfill Gas. Proceedings of the
16th Annual Landfill Gas Symposium. SWANA, Louisville, KY. March 1993.
Edner, S. Combined Heat and Power - The Swedish Experience. U.K. Department of Energy. Landfill
Gas and Anaerobic Digestion of Solid Waste. London, United Kingdom. 1988.
Fisher, A.J. Lubrication of Landfill Gas Engines. U.K. Department of Energy. Power Generation from
Landfill Gas. London, United Kingdom. November 1991.
Hulance, A. Expertise with Landfill Gas Projects: Power Generation at Brogborough Landfill Site. U.K.
Department of Energy. Power Generation from Landfill Gas. London, United Kingdom. November 1991.
Markham, M.A. Landfill Gas Recovery to Electric Energy Equipment: Waste Management's 1991
Performance Record. Proceedings of the 15th Annual Landfill Gas Symposium. SWANA, Silver Spring,
MD. March 1992.
U.K. Department of Energy. Power Generation from Landfill Gas. Harwell Laboratories, Oxfordshire,
United Kingdom. 1992.
Watts, R.A. The Justification of Landfill Gas Recovery for Electric Generation. Submitted Papers and
Abstracts for the 10th International Landfill Gas Symposium. GRCDA/SWANA, Silver Spring, MD. 1987.
4.2.1 Reciprocating Internal Combustion Engines
Bateman, C.S. and R. Currie. Power Generation in Australia. U.K. Department of Energy and
Department of the Environment. Landfill Gas: Energy and Environment '90. London, United Kingdom.
1990.
Chadwick, C.E. Application of Caterpillar Spark-Ignited Engines for Landfill Gas. Proceedings of the
12th Annual International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
Chadwick, C.E. Reduced Power Requirements of Low Pressure Gas Reciprocating Engines. Pre-
Treatment of Landfill Gas. Proceedings of the 13th Annual International Landfill Gas Symposium.
GRCDA, Lincolnshire, IL. March 1990.
Gonzalez, J.G. Selecting the Best Lubricant for Optimum Equipment Performance. Papers and
Abstracts for the 10th International Landfill Gas Symposium. GRCDA/SWANA, Silver Spring, MD.
1987.
Homably, M.R. Lessons Learnt from the Stewartby & Packington Projects. U.K. Department of Energy
and Department of the Environment. Landfill Gas: Energy and Environment '90. London, United
Kingdom. 1990.
Limbrick, A. Electricity Generation from Landfill Gas at Wapsey's Wood. Buckinghamshire. Using Dual
Fuel Engines. U.K. Department of Energy. Landfill Gas and Anaerobic Digestion of Solid Waste.
Oxfordshire, United Kingdom. 1988.
Moss, H.D.T. The Use of Landfill Gas in Reciprocating Engines. Proceedings of Sardinia '91 - Third
International Landfill Symposium. Sardinia, Italy. 1991.
Moss, H.D.T. Generation Using Spark Ignition Engines. U.K. Department of Energy. Landfill Gas and
Anaerobic Digestion of Solid Waste. Oxfordshire, United Kingdom. 1988.
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Owen, W. and J. Smithberger. 1-95 Fairfax County Landfill Gas Project. Proceedings of the 15th
Annual Landfill Gas Symposium. SWANA, Silver Spring, MD. March 1992.
Schneider, J. The Berlin-Wannsee Site - 2.5 Years of Experience with a Landfill Gas Purification and
4.5 MW Combustion-Engine Cogeneration Plant. Proceedings of Sardinia '91 - Third International
Landfill Symposium. Sardinia, Italy. 1991.
Vaglia, R. Operating Experience with Superior Gas Engines on Landfill Gas. Proceedings of the 12th
Annual International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
Young, C.P. and N.C. Blakey. Emissions from Power Generations Plants Fuelled by Landfill Gas.
Proceedings of Sardinia '91 - Third International Landfill Symposium. Sardinia, Italy. 1991.
4.2.2 Gas Turbines
Biddle, C.A.R. Generation Using Gas Turbines. Midlands Electricity Board Tariff. U.K. Department of
Energy. Landfill Gas and Anaerobic Digestion of Solid Waste. Oxfordshire, United Kingdom. 1988.
Esbeck, D.W. Solar Turbines. Incorporated Landfill Gas Experience. Proceedings of the 12th Annual
International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
Schlotthauer, M. Gas Conditioning Key to Success in Turbine Combustion Systems Using Landfill Gas
Fuels. Proceedings of the 14th Annual International Landfill Gas Symposium. GRCDA/SWANA, San
Diego, CA. March 1991.
Taplin, B. and K. Ochel. Mucking: Landfill Gas Extraction & Future Use in a Turbine. U.K. Department
of Energy and Department of the Environment. Landfill Gas: Energy and Environment '90.
Bournemouth, United Kingdom. 1990.
4.2.3 Steam Turbines
Eppich, J.D. 50 Megawatt Steam Power Plant Fuelled by Landfill Gas. U.K. Department of Energy.
Landfill Gas and Anaerobic Digestion of Solid Waste. London, United Kingdom. 1988.
4.3 PIPELINE QUALITY GAS
Healy, R.J. and G. Christianson. Production of Vehicle Fuel (CNG) from Landfill Gas Utilizing Sour
Natural Gas Treatment Technologies. Proceedings of the 15th Annual Landfill Gas Symposium.
SWANA, Silver Spring, MD. March 1992.
Shah, V.A. Landfill Gas to High Btu Sales Using Selexol® Solvent Process. Proceedings of the 13th
Annual International Landfill Gas Symposium. GRCDA, Lincolnshire, IL. March 1990.
Trocciola, J.C. Landfill Methane Mitigation Using a Commercial Fuel Cell. Proceedings of the 17th
Annual Landfill Gas Symposium. SWANA, Long Beach, CA. March 1994.
Wheless, E. Processing and Utilization of Landfill Gas as a Clean. Alternative Vehicle Fuel.
Proceedings of the 17th Annual Landfill Gas Symposium. SWANA, Long Beach, CA. March 1994.
Wheless, E. Compressed Landfill Gas as a Clean. Alternative Vehicle Fuel. Proceedings of the 16th
Annual Landfill Gas Symposium. SWANA, Louisville, KY. March 1993.
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4.4 CONDENSATE AND CONTAMINANTS
Call, N.S. Treatment of Aqueous Condensate From Landfill Gas Recovery Plants. Proceedings of the
12th Annual International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
Carrico, P.J. LFG Condensate Treatment at I-95 Landfill. Lorton. Virginia. Proceedings of the 16th
Annual Landfill Gas Symposium. SWANA, Louisville, KY. March 1993.
Francoeur, C. H2S Control for the Landfill Industry. Proceedings of the 16th Annual Landfill Gas
Symposium. SWANA, Louisville, KY. March 1993.
Maxwell, G. Landfill Owner's/Operator's Experience and Perspective on Municipal Landfill Gas
Condensate Collection and Disposal. Proceedings of the 12th Annual International Landfill Gas
Symposium. GRCDA, Silver Spring, MD. 1989.
Panza, R.A. In Search of a Few Good Treatment Processes (For Landfill Gas Condensate).
Proceedings of the 16th Annual Landfill Gas Symposium. SWANA, Louisville, KY. March 1993.
Peterson, W., G. Vogt, and J. Vogt. Emissions Control and Treatment of High Level Hydrogen Sulfide
and Landfill Gas. Proceedings of the 15th Annual Landfill Gas Symposium. SWANA, Silver Spring,
MD. March 1992.
Sullivan, W. Landfill Gas Condensate Collection and Disposal Using the Vacuum Condensate Drainage
Method. Proceedings of the 15th Annual Landfill Gas Symposium. SWANA, Silver Spring, MD. March
1992.
Vogt, W.G. and J.L. Briggs. Disposal Options for Landfill Gas Condensate. Proceedings of the 12th
Annual International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
5. INFORMATION ON REGULATIONS PERTAINING TO ENERGY USES.
California Air Resources Board. Air Pollution Control at Resource Recovery Facilities. 1991 Update.
Sacramento, CA. 1991.
Davie, D.E. and L. Hollyer. Creating a Favorable Economic Environment for Landfill Gas Energy
Recovery Projects — A Utility Perspective. Proceedings of the 12th Annual International Landfill Gas
Symposium. GRCDA, Silver Spring, MD. 1989.
Federal Register. Standards of Performance for New Stationary Sources and Guidelines for Control of
Existing Sources: Municipal Solid Waste Landfills. Vol. 56, No. 104, Part III, p. 24468. Thursday,
May 30, 1991.
Fitzgibbons, R.G. Beyond the FERC NOPRS: Trends in Electric Utility Regulation. Proceedings of the
12th Annual International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
Greenberg, F. L. Recent Developments. Future Prospects for Sales of Electricity from Facilities which
Burn Landfill Gas. Proceedings of the 15th Annual Landfill Gas Symposium. SWANA, Silver Spring,
MD. March 1992.
Greenberg, F.L. Selling Electricity to Utilities. Proceedings of the 13th Annual International Landfill Gas
Symposium. GRCDA/SWANA, Silver Spring, MD. March 1990.
Hale, B. California's Alternative Energy Program and Landfill Gas to Energy Projects. Proceedings of
the 12th Annual International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
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Hatch, R.F. The Federal Tax Credit for Non-Conventional Fuels: Its Status and Role in the Landfill
Gas Industry. Proceedings of the 14th Annual International Landfill Gas Symposium. GRCDA/SWANA,
San Diego, CA. March 1991.
Maxwell, G. Disposal Options for Landfill Gas Condensate. Proceedings of the 12th Annual
International Landfill Gas Symposium. GRCDA, Silver Spring, MD. 1989.
Petersen, E. Pending Subtitle D Regulations and Their Effect on Landfill Gas Issues. Proceedings of
the 14th Annual International Landfill Gas Symposium. GRCDA/SWANA, San Diego, CA. March 1991.
U.S. EPA. Office of Air Quality Planning and Standards. Air Emissions from Municipal Solid Waste
Landfills — Background Information for Proposed Standards and Guidelines. EPA-450/3-90-011a
(NTIS PB91-197061). 1991.
Wong, P.P. Alternative Energy & Regulatory Policy: Til Death Do We Part. Presented at AWMA
Conference on "Cooperative Clean Air Technology — Advances through Government Industrial
Partnership" in Santa Barbara, CA. March 21 - April 1, 1992.
6. ENVIRONMENTAL AND CONSERVATION ISSUES
Augenstein, D. Greenhouse Effect Contributions of United States Landfill Methane. Proceedings of the
13th Annual International Landfill Gas Symposium. GRCDA, Lincolnshire, IL. March 1990.
Campbell, D., D. Epperson, L. Davis, R. Peer, and W. Gray. Analysis of Factors Affecting Methane Gas
Recovery from Six Landfills. EPA-600/2-91-055 (NTIS PB92-101351). September 1991.
Maunder, D. Non-Technical Barriers to Using Landfill Gas in the U.K. and a Discussion of Some
Solutions. Proceedings of the 16th Annual Landfill Gas Symposium. SWANA, Louisville, KY. March
1993.
National Academy of Sciences. Policy Implications of Global Warming. National Academy of Sciences,
Washington, DC. 1991.
Peer, R., D. Epperson, D. Campbell, and P. von Brook. Development of an Empirical Model of Methane
Emissions from Landfills. EPA-600/R-92-037 (NTIS PB92-152875). March 1992.
Scott, P.E., et al. The Fate of Gaseous Trace Components within Landfill Gas Utilisation Systems. U.K.
Department of Energy. Power Generation From Landfill Gas. London, United Kingdom. November 1991.
Thorneloe, S.A. and R.L. Peer. Landfill Gas and the Greenhouse Effect. Text in Landfill Gas, Energy and
Environment '90. U.K. Department of Energy and Department of the Environment. Harwell, Oxfordshire.
London, United Kingdom. 1990.
Thorneloe, S.A., M.A. Barlaz, R. Peer, L.C. Huff, L. Davis, and J. Mangino. Global Methane Emissions
from Waste Management. Published in: Atmospheric Methane: Sources, Sinks, and Role in Global
Change," pp 362-398, NATO ASI series, Vol. 1-13, Springer Verlag. 1993.
Thorneloe, S.A. Landfill Gas and Its Influence on Global Climate Change. Proceedings of Sardinia '93 -
Fourth International Landfill Symposium. Sardinia, Italy. October 1993.
Thomeloe, S.A., M.R.J. Doom, M.A. Barlaz, et al. Methane Emissions from Landfills and Open Dumps.
In: "International Anthropogenic Methane Emissions: Estimates for 1990." (EPA Report to Congress)
EPA-230-R-93-010. January, 1994.
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APPENDIX C: LIST OF DEVELOPERS AND OPERATING COMPANIES
Company
Address
Contact
Telephone
Number
Fax Number
Landfill Gas Energy Conversion Project Developers
Cambrian Energy Systems
Energy Tactics, Inc., ETI
Gas Resources Corporation
Getty Energy, Inc. (GSF)
Granger Renewable
Resources, Inc.
KMS Energy Group
Lakjlaw Gas Recovery
Systems
Landfill Energy Systems
Minnesota Methane
O'Brien Energy Systems, Inc.
Palmer Capital Corporation
Rust Environment and
Infrastructure
Vermont Energy Recovery,
Inc.
3420 Ocean Park Blvd. Ste. 2020 Tudor Williams
Santa Monica, CA 90405
P.O. Box 7
124 Sills Road
Yaphank, NY 11980
3405 Piedmont Road, N.E.,
Suite 595, Atlanta, GA 30305
7201 Hamilton Blvd. .
Allentown, PA 18195
Stanley Drake
President
Alan Epstein
President
Paul Persico
17330 Brookhurst St. Ste. 260 Paul Kuroki
Fountain Valley, CA 92708-3720
P.O. Box 27185
Lansing, Ml 48909
2600 West Van Buren,
Bellwood, IL 60104
89899 Ballentine Dr., #275
Newark, CA 94560
29261 Wall Street
Wixom, Ml 48393
901 West 94tti Street,
Minneapolis, MN 55420
225 South 8th St
Philadelphia, PA 19106
672 Jerusalem Road
Cohasset, MA 02025
1240 E Diehl Road,
Naperville, IL 60563
P.O. Box 791
Brattleboro, VT 05302
Ralph
Nuerenberg
Vice President
Henry Martin
President
George Jensen
Matt Nourat
Scott Salisbury
Craig
Matacyynski,
Stan Erickson
Directors
Bruce Levy
Gordon Deane
Charles Anderson
Alan McLane
310-314-2727
516-924-5300
404-262-7443
610-481-7061
714-968-5477
517-372-2600
708-450-8400
510-656-8327
810-380-3929
810-380-3920
612-330-6977
215-627-5500
617-383-1293
708-955-6665
802-257-3000
310-314-2731
516-924-5627
404-262-7445
714-964-4054
517-372-9220
708-450-2886
510-656-7927
810-380-2038
612-887-5885
215-922-5227
617-492-7822
708-955-6601
802-257-5851
Notes: BFI is a large developer/operator that is not included, since their landfill gas utilization projects are all in-
house.
Only developers/operators with two or more projects are included.
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APPENDIX C: LIST OF DEVELOPERS AND OPERATING COMPANIES (continued)
Company
Address
Contact
Telephone
Number
Fax Number
Landfill Gas Energy Conversion Project Operating Companies
Energy Tactics, Inc., ETI
International Power
J-W Operating Company
KMS Energy Group
Minnesota Methane
P.O. Box 7
124 Sills Road
Yaphank, NY 11980
1000 Marine Parkway, Ste. 325
Redwood City, CA 94065
P.O. Box 226406
Dallas, TX 75222
2600 West Van Buren,
Bellwood, IL 60104
901 West 94th Street,
Minneapolis, MN 55420
O'Brien Energy Systems, Inc. 225 South 8th SL
Philadelphia, PA 19106
Stanley Drake 516-924-5300 516-924-5627
President
Randy Turley 415-592-9020 415-592-9026
Operations Manager
Mark Westerman 214-233-8191 214-991-0704
Henry Martin
President
708-450-8400 708-450-2886
Craig Matacyynski, 612-330-6977 612-887-5885
Stan Ertekson
Directors
Bruce Levy
215-627-5500 215-922-5227
Notes: BFI is a large developer/operator that is not included, since their landfill gas utilization projects are all in-
house.
Only operators with two or more projects are included.
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APPENDIX D: INTERVIEW SUMMARIES
In June 1992, EPA published a report entitled: "Landfill Gas Energy Utilization: Technology
Options and Case Studies," of which the abstract and table of contents are included in
Appendix A. The report provides an overview of the various landfill gas energy uses and
presents case studies of six landfill gas energy projects in the United States. During
preparation of the report, it became evident that there was a need among landfill gas
developers and others involved in the industry for more detailed information on the technical
and non-technical considerations concerning landfill gas utilization. It was decided that this
information would best be provided by sources with expertise in the everyday operation of
landfill gas utilization equipment. Following are summaries of 13 interviews with experts from
leading companies in the landfill gas industry. The first six interviews were conducted in May
1992 and focussed on technical issues. The following seven interviews were conducted in May
and June 1994 and addressed non-technical issues, such as barriers to the industry. The
information acquired from these interviews was used as the basis for this report.
TECHNICAL ISSUES
INTERVIEW 1; BROWNING-FERRIS INDUSTRIES (BFI)
Interview with Richard Echols, May 29, 1992.
BFI has 5 landfill gas (LFG) to energy projects, 2 under construction
and over 30 on drawing board. Economics is currently a barrier to
energy use at many sites.
Piping
BFI favors below-ground pipe. Reasons: polyvinyl chloride (PVC) has
short life, polyethylene high thermal expansion coefficient, fires are a
greater danger -above ground. They use high-density polyethylene plastic
pipe up to compressor and stainless steel past it.
Monitoring
At the energy sites O2, N2, CO2, H2, and CH4 are monitored with a Daniels
gas chromatoaraph: sampling is once every few minutes. Also H2S levels
are watched, mainly for safety reasons. The methane flow-is determined
after correction for P and T. (On flare sites only monitor temperature
and methane) . Methane set point is 50% if attainable, but this may be
dropped as low as 45%. GC column changes needed much more frequently on
LFG than with other gas analyses. NMOC data are taken to assure that
energy equipment manufacturer's standards are met. Gas NMOC data not
provided.
A distinct diurnal effect on methane concentration was noticed;
variations of 1 to 3% occur. Oxygen normally under 0.5% but with leaks
may easily approach 5%.
Condensate
Collection by automated system is preferred at the field. Disposal
varies depending on local ordinance. Nearly always non-hazardous
(detailed composition data not given by BFI). Condensate slugs have hit
high pressure compressors and caused severe damage ("blow stage apart").
At the energy recovery site, a knockout tank removes additional
condensate before the compressor. (Tank is oversized by a factor 5) .
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Pretreatment
BFI is in the process of standardizing the pretreatment approach to
maximum extent possible at most sites. Gas pretreatment has been very
.dependable, uptime stated to be better than 95%. No plans for
significant changes. Parasitics reported to be about 7% of gross RIG
engine output: 4/3 or 5/2 for compression relative to refrigeration.
Corrosion prevention; high-density polyethylene (low pressure) or
stainless steel (higher pressure) is used.
Basic approach is:
• Inlet condensate removal (see above),
• Comaression. Lamson centrifugal compressors serve the energy
equipment for field extraction on energy projects and also serve
flares. Compressors have baked-on plastic finish.
• Refrigeration to 37-38°F. Refrigeration: Going for skids with
two refrigeration compressors each with 100% capacity. Looking
for bids on refrigeration system designs where refrigerant 22 is
replaceable with alternative.
Reheat to 75-80°F,
• Filtration; 3 micron cutoff the criterion, otherwise not
standard; several different brands used. Pressure drop and
parasitics very small, performance not a problem. Paper element
filters were used in the past but paper elements fell apart.
RIC Engines
As a standard a Waukesha 7042 with a 1025 KW Kato generator is used.
RIC engines use fuel gas compression to 10 psi, then refrigeration and
reheat, premixing or pre-carburetion of most of the fuel/air charge,
then .turbocharge to engine. Small slip stream is compressed to 45 psi
to fuel the pre-combustion chamber. Carburetion: close control of gas
quality to RIC engine and automatic adjustment of fuel/air mix to point
where engine does not have to work against governor to maintain speed.
Methane definitely limits size of energy equipment. No alternative fuel
capability at any site. When gas supply is limited the RIC engines are
throttled or units are taken off-line, as needed. No problems reported
with this procedure. Turbocharger service normal. Turbocharger can
however be a capacity limiting factor especially at lower methane levels
(since it must compress more gas compared to normal natural gas
service).
Material adaptations can include chromed valves and guides but BFI does
not typically specify this. The intent is to determine site specific
needs and modify equipment as necessary.
BFI uses manufacturer's recommended oil; typically Mobil Pegasus. The
oil change interval is 500 hours (to be based on test results from
external laboratory).
Standard crankcase ventilation back into RIC engine.
Jacket water as manufacturer recommends (s225°F).
High pressure compressors have had problems with deposits; have had to
change and clean valves a lot more often especially in the positive
displacement types.
Time between overhauls: follow Waukeshsa guides at this point. May
modify as experience is developed.
Catalysts do not work.
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O&M costs not immediately available.
'Pipeline Gas Cleanup:
BFI has one plant in operation for which they are fully responsible. It
uses the Kryos™ process with methanol. It is working very well.
Another pipeline plant with which BFI is involved is operated by Air
Products and BFI's role is largely as a royalty recipient.
INTERVIEW 2; IAIDIAW
Interview with George Jansen and Matt Nourot, May 5 and May 11, 1992.
Monitoring
Gas monitoring: maintain a 50% methane mix at most sites. Measure
methane, C02, O2, N2-and CO (in certain areas to detect possible fires).
Methane analysis is conducted by Gastech (5 times per week). Other
gases (also again methane) measured twice a month using grab samples
taken to GC. GC methane corresponds closely to Gastech readings. No
"instantaneous" monitoring of gas composition to energy equipment at any
site.
Oxygen/air intrusion into gas: no alarm is used at Laidlaw RIC engine
sites. Equipment will simply shut down.
LFG flow measurement To be more accurate, orifice plates are being
installed in wellheads.
Blowers
Low pressure blowers: several types preferred, Lamson most frequently
used.. Blower life is acceptable without any special modification to
parts. Low pressure gas compressors stated to be one of the most
reliable parts of the whole system.
Condensate
Condensate slugs have been a problem; at one site where sliding vane
compressors were used, sliding vanes were destroyed. Condensate
accumulation in cutoff "deadheaded" gas lines has also been a problem.
Although condensate caused compressor or other equipment damage at some
sites, re-piping so that condensate was blown into a low collection trap
at the inlet pipe to the compressors appears to have solved problem.
Better supplemental low point drainage has also helped. Slug catchers,
designed by Solar Turbines, are used at some plants employing Solar
equipment.
Condensates can also be a very large problem where they are classified
as a hazardous waste, as is the case in California. The incremental
compression with various energy uses, such as with lean burn RIC
engines, can generate a large amount of extra condensate, in comparison
to flaring. Disposal cost at up to 70 cents/gallon can put a stop to
energy generation.
Pretreatment
Naturally aspirated RIC engines initially had minimal cleanup. Wear was
rapid (engines corroded out within a few thousand hours) and this is now
thought to be due to the fact that condensate was entering engines.
Everything improved once gas cleanup was practiced.
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Gas processing sequence'is normally:
• Inlet scrubber (large diameter vessel with demister pad in top);
cleaned out periodically by simply "washing the vessel out."
• Compressor; if two stages, there is .normally intercooling.
(Because of condensation with cooling, there is often a slug
catcher between stages.) Different types are used, including
one-stage sliding vane and two-stage. There is a trend toward
standardization because of spare parts considerations
(Breakdowns have caused substantial downtime). Particulate
loading has been associated with compressor valves falling
apart, resulting in parts being sucked into compressor. The
chief engineer has done a lot of work on compressor valves,
redesigning them so that broken parts stay in one spot. Replace
valves (with spares on hand) on a six-month schedule to prevent
this type of problem.
• Refrigeration; cool gas to below 35°F (may only get down to 40°F
in summer).
• Reheat to above ambient, 75-90°F, to get any entrained liquid
aerosol into a vapor state. Often done by heating cool gas
stream against the inlet gas off the compressor.
• Filtration (Fiberglass; manufacturers Perry, King tool, PECO
0.1 to 1 micron cut-off). Dry filtration (PECO, 10 micron cut-
off) . The filtration works well and filters look clean on
normal replacement schedule of 6 months. Pressure drop normally
low, less than 1 psi; gauges (monitored and recorded once daily)
showing rising pressure drop would indicate need for change.
There appears to be no notable or "LFG specific" filtration O&M
needs.
Corrosion
Carbon steel, where used in process system, erodes. Loose corroded
particles present danger of getting into the RIC engine cylinders. They
can also cause fouling of filters.
Material Modification
Manufacturers of RIC engines (see below) have not provided stainless
steel in skids in the past, so Laidlaw has had to provide. Have been
replacing carbon with stainless steel over time as replacement needs
occur.
RIC Engines
Gas is limiting factor at most sites, i. e., insufficient to fully power
energy equipment. When gas supply drops, the engines are throttled or
taken off-line. Both methods are said to work well: Fuel
supplementation is not done. Engines are stated to throttle well,
maintaining their fuel efficiency. At one site (Guadalupe) one RIC
engine is run during peak periods (noon-6pm) only.
Laidlaw uses several types of RIC engines:
• Cooper naturally aspirated. 500 KW (11 in place). Heat rate
13,000 to 15,000 Btu/KWh LHV (lower heat value) or about 14,000
to 16,000 HHV (higher heat value)
• Cooper lean burn engines, 750 KW .(2 in place)
• Cooper lean burn engines, 1750 KW 16 cylinder turbocharged
Waukesha lean burn engines. 1,100 KW, 12 cylinder, turbocharged
30-35 psi., (4 in place).
See Jansen (1992) for further information and overview of energy
equipment. All lean burn engines have heat rates near 10,000-11,000 LHV
D-4
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or 11,000-12,000 HHV Btu'/KWH. As far as Laidlaw knows, all parts of the
above RIC engines are standard.
Laidlaw goes for 85% RIC engine availability: An averaged power output
over time, of 85% of what the nameplate says. In other terms, losses due
to scheduled plus unscheduled outages, plus downrating from nameplate
value due to LFG use and other factors, are expected to total no more
than 15%.
With clean-burn Cooper and lean-burn Waukesha engines that have pre-
combustion chambers, the refrigeration (see gas handling, analysis and
pretreatment section above) has been found to be especially beneficial
as pretreatment. Without refrigeration and other good cleanup, deposits
can develop in the orifices of the pre-combustion chambers that can
cause pre-detonation.
Use Mobil Pegasus oil (454). Typically get 2,000 hours. Typical
analysis: metals, pH balance, ash content. Analysis is approximately
once a week. Oil filtration with standard filters. RIC engines consume
typically one to five gallons per day. Normal crankcase ventilation.
Bearing wear was fairly severe until oil was changed to current type
described previously above. Deposits were a problem with early operation
on unclean LFG and with early oils but not so now; currently, deposits
with cleaned LFG are characterized as on high end of normal with natural
gas.
Carburetion: Operators use field methane measurements as index for
setting carburetion; cylinder temperatures also an index. On naturally
aspirated units, overfueling is needed to lower NOX. Carburetion is set
to maintain a minimum CO level .in the exhaust. Cooper Superior clean
burn engines use an air/fuel ratio controlling system (Ultronics) that
monitors each cylinder and controls spark timing on each cylinder.
Except where controlled by Ultronics system, spark ignition timing is
simply set by manufacturer's recommendation or based on Laidlaw
experience over the years. Fuel metering system needs no special extra
maintenance/cleanup as long as gas supply is clean.
Waukesha's: Control air/fuel ratio on the basis of exhaust oxygen
content. Problem is that monitoring is relatively infrequent. If
methane drops, RIC engine runs very erratically and quite unstably. If
methane goes rich engines will detonate and severe damage can occur.
Maintenance intervals: 10,000 to 15,000 hours on top end. Entire
rebuild at intervals of 25,000 to 30,000 hours. Major overhauls take as
long as 15 to 20 days; overhauls are scheduled for time of low power
sale rates in winter. Maintenance cost; rough estimate is 2 to 2.2
cents per KWH.
RIC engine jacket water temperature: Waukesha's 200°F, Coopers about
180°F.
Very bad experience with catalysts on naturally aspirated engines; they
have been quickly inactivated by exhaust gas components.
Turbocharger performance can be regarded as normal; similar to what
would be expected on natural gas service.
Turbines
Laidlaw operates two Solar Centaur and five Solar Saturn combustion gas
turbines, all purchased recently from Solar. Net efficiency of Centaurs
is 14,000 HHV Btu/KWH and of the Saturns approx 15,000. (Saturn
turbines are recuperated; this design was intended for application in
D-5
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air quality areas where RIG engine NOX emissions would not be
permitted). Modifications for LFG, if any not known to Laidlaw.
Turbines operate on temperature topping. Providing LFG is not limiting,
turbines can adjust well to fuel energy content changes (although
Laidlaw feels that if fuel energy content fell low enough, compressors
might not be able to pump enough LFG to turbines — i. e., with lower LFG
energy content, turndown capability is terrible).
Time between overhauls estimated at 30,000 hours.
Steam boiler
The plant consists of a Zurn boiler and General Electric turbine with a
nominal nameplate rating of 20 MW. It is operated at 15 MW output
because gas supply is not sufficient. Ratings: 14,000 Btu/KWH (LHV),
equivalent to 15,000 Btu/KWH HHV.
Because local emission standards would become stricter no alternate fuel
supplementation is used.
No elaborate cleanup of incoming gas other than for particulates. The
boiler tubes are stainless steel. (This may, however be standard
design). Zurn did do some modifications to burners. Have seen some
particulate buildup on tubes but these are felt to be unrelated to LFG.
Laidlaw believes fuel/air ratio controlled by stack monitoring of 02.
If field methane drops, operators simply reduce overall gas extraction
rate so that methane stays at acceptable level.
Boiler goes down for routine maintenance once a year, major maintenance
every third year. Overall observation is that, where there is enough
LFG to supply an economic sized (20MW and up) plant, steam plants work
very well.
INTERVIEW 3; PACIFIC ENERGY
Interview with Alex Roqueta and Frank Wong, May 15, 1992.
Pacific Energy tries to maximize methane recovery. Maximizing the
methane at the wellhead and installing additional wells maximizes total
Btu's. Methane concentration set point is site specific, normally 47 to
52%.
Corrosion and moisture contents stated as biggest problems with LFG.
Piping
Vertical wells are preferred, sometimes supplemented by trenches to
control migration. Polyethylene, PVC, or sometimes steel pipes are
used. Pacific Energy strongly prefers above ground piping; easier to
repair.leaks, fix condensate blockages, etc. They believe that O&M is 3
to 4 times higher with below ground systems. Where possible, mains are
placed on native land to avoid subsidence problems.
Pretreatinent
Pacific energy's philosophy is to limit pretreatment to filtration with
condensate removal. They feel that although expense is higher than with
cleaner gas, they work reasonably well; believe that expense of more
stringent pretreatment is not justified.
Condensate: automated extraction system being implemented in field
where possible; trying to design for anticipated rather than current
regulations. Underground storage is avoided. Midpoint range for
D-6
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condensate handling suggested around 12-15 cents per gallon (The range
is a few cents up to about 90 cents if condensate is deemed hazardous.)
Pretreatment sequence:
• Condensate knockout. Final condensate knockout before
compressor by King Tool, tank with demister pad (exact
configuration not available).
Compression: keep gas warm - 100 to 150°F, normally closer to
150°F. Compressors that serve the RIC engines (Gardner-Denver
and Ariels, oil lubricated) serve for field extraction as well.
Typically pull 40-80 in. H20, discharge to Cooper RIC engines at
80-90 psi. Condensate getting to compressor has not caused
serious damage ("bent a valve or two out of shape"). The motor
senses excess load and shuts down.
• Filter (first a coalescing then particulate) to engine.
Carbon steel used in system, experiencing some contaminant corrosion.
slowly being replaced by stainless. In hindsight Pacific Energy would
have used stainless steel where it has used carbon.
RIC Engines
Cooper lean burn turbocharged engines used at all but one site (12
cylinder, 12SBTLA, 1,350 KW and 16 cylinder 16SBTLA., 1,875 KW). Heat
rates are 11,000 to 14,000 Btu/KWH HHV. The 12 cylinder is a little
less efficient than the 16 cylinder. Elliot turbochargers give about 12
pounds of air boost.
RIC engine operation is governed to produce a set power output.
Carburetion
Daniels GC monitors methane every 6 minutes. Air/fuel ratios adjusted
automatically based on the Btu content. Adjustments are partially
automated and include spark advance control. Much greater efficiency
and easier operation on the RIC engine with the automated air/fuel
panel, but details are not available.
There is LFG supplementation with natural gas at some sites. Natural
gas stated to improve RIC engine smoothness and efficiency. The
GC/automated panel system for carburetion control apparently works well
under these circumstances. The supplementation is often at periods of
peak power sale price, to maximize revenue.
There have been a number of changes in the fuel system — throttle
orifices were changed to maximize efficiency. Have burned out pre-
ignition cups on RIC engine where fuel ignition starts.
Monitoring-
The gas concentration is monitored by GEM 5000 infrared-based absorption
system. Pacific Energy states that methane does not change in a short
period of time except for generation rate decline (say 3-5% a year of
total extraction rate at closed sites). Most sites are gas limiting.
Exhaust gas temperature is followed because it can indicate non-firing
cylinders, valve problems, etc.
There are alarm and engine shutdown levels for oxygen (levels not •
given). Oxygen typically runs 0.2 to 0.3% at the plant.
Oil: designation not available; oil monitored weekly by outside lab.
Maintenance
D-7
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RIC engine shutdown is a preferred approach to gas limitation since
ratio of power produced to incremental O&M (which is relatively load-
independent) can become unfavorable.
Maintenance: four top ends for every bottom end. Maintenance is planned
at ends of specific intervals, (8,000 hours from case studies), not
based on observations except in special cases.
Turbocharger maintenance more frequent than with natural gas.
INTERVIEW 4: GSF ENERGY/AIR PRODUCTS
Interview with Paul Persico, Brian Pell and Thomas Normoyle, May
27,1992.
GSF's principal activity is purification of LFG to pipeline quality.
They purify at given sites by first pre-treating in a solid adsorbent
bed which contains, among other things, activated carbon and sulfur
removal sorbents. The gas then passes on to a pressure swing absorption
(PSA) system where CO2 is removed using a molecular sieve. The current
approach has been in use since 1986.
GSF adjusts recovery to minimize N2 entrainment since there is no easy
way to remove this gas from methane. Extraction stress is minimized to
limit N2 to about 1%. Adjustment is by opening wells that show no N2
entrainment, and throttling those that do; well monitoring practice is
typical except for the N2 limit. Measurement is by GC. For low Btu
uses criteria are less stringent, adjust CH4 to 52-55%. Combine
vertical wells and horizontal trench wells. GSF does a five-gas
analysis (CH4, C02, N2, O2, H2) , of what comes into the facilities at
least daily. Most sites are gas-limited.
Condensate removal in a vertical tank, where velocity is reduced, then
mist pad in most cases. Condensate treatment varies by site, according
to needs of local ordinance.
For pipeline purification, sites use a single high pressure
reciprocating design compressor to extract the field and supply gas
purification equipment. Compression is to range of 100-400 pounds.
Compressor down-time not available but down-time stated to be not as
much of an issue as other areas of the process. Dryness: dew point -
80°F (pipeline standard).
Earlier sites used- Selexol™; GSF then determined that the current
molecular sieve approach was preferable. Some sites still use selexol.
Selexol purification temperature is slightly above the freezing point of
water. GSF finds that selexol solvent purification is straightforward
and contaminant buildup is no problem.
GSF states it does well with carbon steel; does not use stainless
piping. Plastic piping up to first separator and then carbon steel
after.
Overall on-line time is over 90%. Greatest amount of down-time is
because of the pretreatment section. Greatest fraction of the
pretreatment section down time is for scheduled maintenance, principally
changing iron sponge which is used for sulfur removal.
Breakeven scale might be of the order of 3xl06 cubic feet per day of
incoming gas. Breakeven sale price might be in the range of $3 to $4
per million Btu.
D-8
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Maintenance: Replace pretreatment column packing once every 6 months.
The pretreatment column acts as a guard bed to the PSA molecular sieve
column. No replacement of the molecular sieve column has yet been
necessary at any site.
No plans for any major changes in gas pretreatment section.
INTERVIEW 5; RUST ENVIRONMENT AND INFRASTRtTCTDRE/WASTE MANAGEMENT OF
NORTH AMERICA
Interview with Chuck Anderson, May 5, 1992.
WMNA has assembled good statistics that indicate that 56% of energy
equipment down-time is attributable to gas system malfunctions/problems.
Probably about 2/3 of energy sites are gas limited and 1/3 have excess
equipment capacity.
Common design saves design costs at sites, allows economical stocking of
more spare parts (Markham, 1992). Stocking is.such that it permits
ready replacement of entire RIC engine assembly if needed.
Monitoring
Gas grab samples from wells are monitored for N2 and O2. A high N2 level
(8 to 10%) indicates potential overpulling. An 02 level of 1% or above
is a sign of leaks or other problems. At the plants, the gas is again
monitored for C02, CH4, N2 and O2 by GC. WMNA aims for "quality of gas
before quantity" and maintains a CH4 set point of 53-54% (may be lower
in some cases such as where system is trying to control migration).
Methane concentration undergoes seasonal changes.
Chlorinated and fluorinated compounds are analyzed, as well as a list of
40 or so other compounds. Chlorine compound concentration varies from
site to site by a factor of five and averages about 150 micrograms per
liter (or 5 micrograms per Btu). NMOCs concentrations are typically
1,200 ppm as hexane; H2S averages 30 ppm commonly up to 100 ppm. Other
WMNA data were not available as of interview.
Pretreatment
Gas pretreatment characterized by WMNA as "moderate capital and low
maintenance". Pretreatment consists of:
• Condensate removal with tanks at line low points, placed
strategically around the field.
• Knockout tank; WMNA terms "suction scrubber." Condensate slugs
once a year or less. Has, very rarely overshot suction scrubber
and reached equipment. Slugs can be associated with cold-
weather startups.
Mesh pad (i. e. demister; shoot for taking out 95% of entrained
liquid with the demister).
• Compression (to outlet pressures depending on use).
• Gas cooling (to design dewpoint about 80°F, or to 10-15°F above
ambient for RIC engines; to about 90-100°F for turbines).
• Finer filtration (3 micron cutoff with coalescing filter; 0.3
micron for turbines)
• Gas reheating (to ca. 20°F above dewpoint for engines; to 160°F
for turbines).
Skid cost for this stated at "anywhere from $150,000-200,000" Figures
for parameters above are approximate.
Compressors
D-9
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WMNA uses low pressure compressors and favors positive displacement
rotary lobe types; mostly Roots, 800-1200 cfm. Compressors used are
belt, as well as shaft driven. Gears are changed out to match
speed/capacity to gas pumping needs. Usually the compressors are
somewhat oversized for expected gas flow. Cast iron interior compressor
parts come in contact with LFG; no corrosion problems seen with this.
Compressor down-time: due to maintenance, less than 1%, and due to
problems, less than 1%. Overall, down-time less than 1% on low pressure
and on the compressors for the high pressure turbines about 3%.
Corrosion
Corrosion in pipes and process equipment is prevented by use of
stainless or epoxy coating. Bare carbon steel avoided everywhere,
except in the compressor. Corrosion of heat exchange equipment for
post-compression cooling of high pressure gas to turbines has been seen.
Had to replace some of the header boxes on the tube bundle after they
corroded out.
RIC Engines
WMNA uses Caterpillar 3516 series engines with an approximate output of
800-815 KW on LFG. The newer engines are "low pressure" types which
were adapted for LFG by Caterpillar (Chadwick, 1990) . Some older models
are conventionally turbocharged and need a separate auxiliary high
pressure (35 psi?) LFG compressor. Low pressure engines are giving
9,760 Btu/KWH (LHV) of electrical output (with generator loss),
operation on average is 10,670 Btu Ihv/KWH after parasitic losses.
These translate to about 11,000 and 12,000 Btu/KWH HHV respectively.
Hours on "high pressure" are about 28,000 and on low pressure are
23,000.
Valve stems/guides are chrome-plated. Jacket water 230-240°F.
Final filtration for Caterpillar engines: filters with technilab
elements, 3 micron cutoff; designed for 1/2 psi pressure drop. Last
filtration between cooler and preheater on the engine skid. Filters are
trouble-free.
Methane to engine monitored once an hour with a GC system (Daniels).
Has full computer which logs operating hours on equipment, fuel flow,
and other information.
Oil used: DA Blueflame type BG, SA 40 weight oil, viscosity 13.5
centistokes at 100°C; nominal TBN is 10 (although usually found to be 9
or 8.5 on initial testing). Change interval about 750 hours. Oil
analyzed twice a month. Oil filter is a Nelson-Winslow unit which
supports the TBN, i.e., filter contains base which dissolves to replace
that depleted in the oil in use. Oil reservoir temperature at 210-
240°F. Oil change requires about 150 gallons. Engine oil consumption
other than for changes averages about 2 gal/day. All oil-associated
costs stated to run about $20,000 per year.
Fuel meterina/carburetion approach: based on keeping exhaust oxygen at
7%. (1% O2 triggers alarm, 3% a shutdown). Periodic adjustment is
necessary since relative mass flows and s'toichiometry vary as relative
fuel/air temperature varies. Adjustments are by operator and occur only
as frequently as exhaust gas O2 is monitored "maybe once a day—maybe a
few times a week" by a hand-held portable meter (Teledyne). LFG exhaust
oxygen sensors do not currently work. WMNA does have an exhaust gas
temperature criterion: Under 1,200 degrees, and typical values average
close to 1,100. Higher temperature is stated to be associated with
accelerated,wear.
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Set spark to 25-30° advance, adjust based on exhaust gas temperature,
retard if detonation detected; try to run without detectable detonation
(this contrasts to Cat recommendation which is to run just at advance
where some detonation is detected). Normally don't adjust spark much.
Part load operation is said to be good down to 50%. Heat rate at 50%
load = 11,620 Btu/KWH compared to 9,700 Btu/KWH at full load (both
LHV) .
Deposits: occur in combustion chamber walls, top of piston domes,
(where too much buildup is associated with detonation) and occur all the
way into the exhaust system. Deposits are mostly silica and calcium,
and part may come from oil ash. A worst-case sequence of events can
occur where deposit particles cause scoring, then blowby, allowing more
oil to come in and creating more deposits. Deposits stick to
turbocharger expansion section parts, or flaked off parts hit expansion
section and cause damage. Because of deposit problems, turbochargers are
now removed and replaced with each top end overhaul while the old ones
are cleaned up. Deposits stated to be the biggest problem.seen with 1C
engines, as compared to such engines operated on natural gas.
TOD end overhauls at Caterpillar's recommended interval of 8,500 hours
(apparently), based on observation of detonation which mandates deposit
cleanout, and oil consumption which indicates guides have loosened up.
Bottom end expected at 30,000 hours or more, (not there yet). Top ends
relatively inexpensive at $16,000 per engine, bottom ends more in
neighborhood of $40,000 to $50,000. Engines 95.5% on-line (4.5% down
time) when gas is available. Possibly an even split between scheduled
and unscheduled maintenance. Wear: See some valve wear, when going
beyond recommended life on the valves. Valve faces show erosion grooves
at that point.
Engines do fairly well on emissions: however engines may be on occasion
above the 2 g/hp.hr Cat says should be attainable. WMNA does not "try
to permit right to the manufacturer's guarantee" but leaves a little
leeway. WMNA goes to turbines rather than operate too close to NOX
limit at a given site.
Gas Turbines
Turbines are mainly Solar Centaurs, producing 2,800 to 3,500 KW net on
LFG. WMNA does not know of any specific materials changes made for
turbines. WMNA prefers RIC engines over turbines.
Fuel metering, control and handling
Each turbine site has a GC and gas to each turbine is individually
monitored. Injector orifices in the combustor doubled in number to 20
to allow sufficient fuel influx. Also doubled fuel trains to fuel
valve, loader valve, and primary and secondary shutoff valve. Turbine
output normally controlled by temperature topping; measuring temperature
at point between second and third blades of expansion section and
increasing fuel until temperature set point is attained. With turbines
the alarm temperature is only 15°F above, and trip (shutdown)
temperature only 25°F above the recommended operating temperature, hence
increases in LFG methane can easily activate (undesired) turbine
shutdown. WMNA consequently operates temperature topping set point a
little lower than natural gas practice.
There is higher gross power on LFG than on natural gas. This causes
greater load on gearbox and is stated by WMNA to be associated with more
frequent gearbox failures.
Wear and deposits: Deposits containing silicon and antimony, among
other things, have built up on turbine blades and tips at sites;
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principal problem was at the blade tip on a part termed the tip shoe
(minimizes blade-housing clearance). This causes extra overhaul work.
Also, unexpected turbine damage problems at two sites occurred with
carbon deposit on combustor fuel injector (Schlotthauer, 1991) . It was
overcome by gas cleanup modifications including a coalescing filter and
delivery system design changes. Another infrequent source of damage is
foreign object ingestion. One case was due to ice.
Operators who understand turbines well are harder to find and turbines
are harder to troubleshoot. Troubleshooting can be time consuming.
Turbine turndown is poor since air compression work, a high fraction of
even maximum output, is fixed regardless of fuel burn and can consume
all expansion section power at even moderately lower fuel inputs.
Turbine overhauls: Intervals of 30,000 hours, more or less. Cost about
$150,000. Overhauls based on various checks: borescope combustor,
compressor and turbine section. Look at compressor discharge pressure
and turbine power output at temperature topping and look for any
degradation. Vibration monitoring and lube oil analysis also done.
On-line time is stated (published) by WMNA to be 94% (Markham,1992) .
Scheduled down time is about 2%. There are 3 maintenance shutdowns per
year so unscheduled/scheduled maintenance time is in a ratio of 2:1.
Fuel gas compressors have about 3% downtime; their maintenance is
scheduled simultaneously with the turbine maintenance.
INTERVIEW 6s CATERPILLAR
Interview with Curt Chadwick, May 7, 1992.
Background note: Engine being discussed is a Caterpillar 3516 RIC
engine, nameplate net approximately 800 KW. Heat rate near 11,000
Btu/KW HHV (Cat. quote 7270 Btu/hp.) Design adaptations for LFG are
discussed in Chadwick, (1990). Specific materials adaptations to LFG
not given.
One advantage of a low pressure RIC engine is that one compressor can be
avoided. A low pressure engine cuts capital by compressing fuel and
gas together with the turbocharger. Parasitic load is minimized by
compressing fuel and gas to only the minimum pressure required: the 20
psi manifold pressure - Lowered capital and parasitics are independent
of the need for only a low pressure auxiliary blower. No problems seen
with turbocharging the fuel-air mix as opposed to the normal practice of
turbocharging solely air.
Gas consistency is important (implying variations in it, typical of LFG,
can be an important concern—this is so for power output, other
operation, and emissions considerations). Inadequate gas supply, less
than forecast, was noted by Curt Chadwick to be a frequent problem;
field overpulling was noted to be a problem.
Any low pressure gas compressor—variable or constant speed—that is
reliable can be satisfactory—2 psi delivery pressure down to below 1/2
psi (engine needs 5 in. H2O) . Ideally downtime limited to 1% or less
Stainless steel or use of epoxy coatings with carbon steel are observed
to cure corrosion in gas handling equipment.
Contaminants: Chlorine compounds are most important; should not exceed
40 microgfams per Btu. Corrosion/maintenance increase with chlorine
compound content. Chlorine analysis on startup is recommended. One way
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to remove chlorine compounds might be to dry the gas and then filter it
(0.4 micron). Sulfur not normally a concern.
Caterpillar promotes LFG drying and believes it is cost effective ("A
net winner; however, cost tradeoffs are not fully worked out"). Gas
drying by refrigeration preferred down to dew point ca. 38°F because it
takes out corrosives like organic acids and is also-somehow, mechanism
not known—effective in preventing deposits in engine that otherwise
occur without it. Gas refrigeration stated not a major parasitic load.
Oil life is improved with refrigeration drying (ca. 600 hrs interval
between changes goes to 1,200 hrs). In any case free water in the gas to
the engine is to be avoided.
Condensate carry through will be associated with short oil life and high
wear metals.
Catalysts don't work; emissions considerations limit lean burns to four
per site.
Alternate fuels; easiest to switch over (say switch over one of 3 or 4
engines) to all natural gas. Feels LFG/natural gas premixing equipment
, and consequently operation on LFG/natural gas blends cannot work too
well.
Carburetion: Based on exhaust gas oxygen and on methane content of the
LFG; make adjustments to the fuel/air ratio "by microprocessors based on
methane percentage". Control the LFG and air temperature for closer
metering of ratio. Can use field data for further adjustment. Exhaust
oxygen sensing, as on conventional natural gas engines, is a problem
because sensors don't last in LFG exhaust (Hydrogen Chloride attack)
Oil
Several kinds of high Brake Mean Effective Pressure (BMEP) natural gas
engine oils are available with TBN=5 or greater. Change intervals vary
depending on circumstances from a low of 400 hours to a high of 2,000
hours. Change intervals based on analysis and experience; parameters
include oxidation, nitration, TEN depletion, wear metals. No additional
actions needed'in regard to oil filtration. Initial operation: monitor
the oil more frequently.
Crankcase ventilation: a measured amount of air circulates through the
crankcase by design, no modifications needed.
Jacket water temperature; 230°F or so unless heat recovery is practiced,
in which case it can go up to 260°F.
Adjust spark advance by detonation based control; optimum advance is
where there is minor detonation. (New 3,600 series engine will have
more sophisticated control: sensors will assess combustion speed and
use the information in feedback control of carburetion and spark
advance).
In terms of operating ease and efficiency, performance on turndown is
quite good down to approximately 50% of maximum load.
Deposits, though a problem, do not normally result in wear. Deposits
chipping off can however damage turbocharger.
Top end overhaul is normally based on blowby, the consequence of wear in
the valve guides, and valve face regression. For major overhaul of
pistons, rings and liners etc. look at blowby, oil consumption and
relative power. Deposits can trigger overhaul.
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Emissions not too significantly different from natural gas; 98%
destruction efficiency of NMOCs stated to be achieved. Independent test
outside Caterpillar has shown that destruction efficiency is much
higher. Exhaust gas temperature not (at least normally) a concern.
Cat will routinely guarantee operating costs/KWH at between 0.7 and 1.2
cents/KWH depending on various factors.
In summary Caterpillar's principal recommendations and suggestions are:
• Thorough condensate removal.
Refrigeration (expressed as "gas drying" by Caterpillar).
Chlorine content below 1,000 ug/liter (in alternate terms 40
ug/Btu).
• Filtration criterion, 98% of particles 0.4xlO~6 m or larger.
• Use of high TEN, high Brake Mean Effective Pressure natural gas
engine oils, of which several are available.
• Frequent oil analyses on start-up until operating experience
indicates these can be lessened.
If pipeline gas supplementation is needed, Caterpillar recommends that
one or more engines be fully dedicated to natural gas. This would
minimize control problems which might occur with blending. Replacement
of the turbocharger expansion section with a cleaned, rebuilt spare is
recommended if gas refrigeration is not practiced or if deposits are
observed. Other operational aspects are largely identical to the
engines' operation if it were fueled by pipeline gas.
For comparison the recommendations from Waukesha are included below:
• LFG refrigeration pretreatment,
Stringent filtration,
• More frequent cleaning of fuel metering equipment than on
pipeline gas is advisable, particularly when gas pretreatment is
less stringent (i.e., no refrigeration).
• Engine coolant temperature 220-240°F.
High TEN oil.
NON-TECHNICAL ISSUES
CAPITAL CORPORATION
Present: G. Deane, J. Pacey, and S. Thorneloe, May 18, 1994.
Palmer has been in the LFG end use business since 1983. They have two
boiler use projects; Raleigh, NC., and Scholl Canyon, Glendale, CA.
(under construction). Palmer also has one reciprocating internal
combustion engine (RIC) project at Central Landfill in Rhode Island, CT.
They are now looking at a LFG conversion to pipeline quality gas
project. Palmer has developed electricity generation projects at
Burbank, Marina, Southeast, and Yolo, all in CA. The Marina and Yolo
projects were sold and the other two are now closed due to expiration of
Standard Offer 4 (SO#4) utility contracts.
Barriers are business issues not necessarily unique to LFG. For
example, an LFG project has the same pipeline-related issues as a non-
LFG project. However, for LFG you will probably need a separate
dedicated pipeline because LFG cannot be transported through existing
gas pipelines. In the Raleigh project, the local utility complained to
the Public Utility Commission (PUC) that the LFG project was encroaching
upon their franchise territory. However, the PUC decided in favor of
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the LFG project. This delay added several unexpected, extra months to
the project schedule.
Financing
Palmer had a funding problem in the Glendale project, although not
because it was an LFG project. The project wasn't big enough for the
lending institutions. Also lenders wanted an environmental audit
because environmental liability could lead to project foreclosure. An
audit would undoubtedly cause considerable time and money expense, as
well as uncover many issues of potential risk. It took some time and
effort to convince lenders that the CERCLA exemption sufficiently
protects them and the audit was not required.
The small size of these projects, coupled with limited experience,
developing technologies, and issues of lender liability under Superfund
create a general reluctance by lenders to become involved in LFG
projects. Even at a size of $10,000,000 the project size is too small
for large lenders so the mezzanine firms, or a few specialized banks are
the lenders. This increases the project's interest rate by about 2% or
more.
Most landfill owners/operators know their business, but do not know the
energy business. Without expert energy negotiating skill, they may have
difficulty when they deal with a utility or an industrial customer.
They will probably not know about state Public Utility Commissions
(PUCs).
Taxation
Federal reserve rules limit banks to a maximum of 25% equity investment
of a Section 29 LFG project, however they can do 99% of a low income
housing project because it is exempt. If we could see the rules changed
to exempt Section 29 projects it would facilitate bank involvement.
Friday's Wall Street Journal noted that the IRS is trying to regulate
partnerships established for tax-oriented financing. Private developers
do bring in tax-oriented investors; the IRS says it will look at the
intent of Congress and allow people who invest in the low-income housing
to continue. We need to have the same opportunity with Section 29
projects.
There is a California possessory interest tax where a municipal landfill
is tax exempt. If a private organization is working on the landfill
with a LFG project, then the private entity will be taxed as if a
portion of the property is private property. The tax is calculated by
assessing the royalties that you have agreed to pay to the owner. They
take the forecasted royalty over the project life (term of the contract)
and discount it at say 8% to bring it to af present value, and say that
is the basis of the tax bill. This happened at Yolo, CA. - the tax bill
was equal to the royalty amount. This in effect says that because you
agree to pay the municipality for the gas, the State has a right to tax
this amount, or a portion thereof.
Utilities
"Our experience is that we can work with staff. We do not try to go
over the heads of the staff.
If a utility changes their policy regarding interest in an LFG project,
then some difficulties can occur; for instance with Palmer's PG&E
projects in CA.
A New England Power (NEP) representative at a recent EPA meeting,
chaired by Cindy Jacobs, gave an excellent discussion of why NEP wanted
td do some projects. The NEP issued a green RFP which was quickly
approved by MA; NH took their time in approving; and RI is giving them
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grief. The NEP is regulated by three PUC's and the PUC's were required
to approve the NEP program. This has added at least a year to the
process. The'PUC's should be in agreement before the NEP asks for bids.
Interconnects
To know what to expect with interconnects, you need to have experience
and familiarity. The main thing to be negotiated is what you can do and
what they will do. Usually you are at the mercy of the utility. If you
can negotiate you can save money. A developer may not know the cost of
the interconnect initially, but he should ask the utility up front for
the cost of interconnect. The utility will require a conceptual, or
preliminary set of plans for review. The response for review depends on
the attitude of the utility. A period of from 30 to 120 days for review
is reasonable in our experience.
The New England utility would not allow us to build the power line. The
utility built the power line and we financed it for about $400,000. The
same thing occurred on the pipeline in Raleigh, NC, where the utility
did not want this project. Rather than fight the Raleigh utility we
paid them to construct the pipeline.
Air permitting concerns
Air emissions are definitely one of the major issues. In Palo Alto the
Bay Area Air Quality Management District (BAAQMD) wanted to sum the
maximum emissions from the flare with the maximum emissions from the
engines. We explained that there was only a certain amount of LFG - it
either went to the flare or to the engines, it could not go to both at
the same time. They said each was a point source! There is no offset
(avoided fuel at power plant) incentive for these projects.
I believe we needed a.permit to add wells, at least on our Burbank
project, but it should not be necessary. The regulators create
difficulties for adding environmental control equipment.
It would be helpful if EPA could give general guidelines to states
relative to LFG recovery operation. Where extraction systems are
considered environmental control measures, they should be exempt from
property or state sales taxes. Exemption from our RI project was a hard
sell because a landfill does not fit the normal exemption definition
(usually this involves a pollution control system placed on a stack for
a manufacturing facility). We are generating emissions because we are
extracting gas from a landfill.
Boilers
Afraid that LFG may contaminate their equipment, neither Ajinomoto (in
Raleigh) nor the City of Glendale initially wanted to accept LFG in
their existing boilers. Palmer provided a new dedicated boiler for
Ajinomoto with the stipulation that it would only burn LFG. At Glendale
the LACSD helped convince the City that LFG would not harm their
boilers. There is a mind set in industry that LFG is a dirty gas, so
they do not want to handle it.
Boiler installation may, or may not be, expensive depending on boiler
size and/or permit compliance. At our future Milliken Landfill project
in San Bernadino it would be very expensive to put in a separately
dedicated boiler and get it permitted through the SCAQD. It would be
much easier to get this project on line by using existing boilers and
simply adding on to existing permits. There is an iridustrial customer
near the Milliken landfill in San Bernadino who simply refused to
consider taking the LFG in his existing boilers or steam turbine.
INTERVIEW 2; BROWNING-FERRIS INDUSTRIES (BFI)
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Present: John Bean and 'Richard Oakley of BFI, Michiel Doorn,
John Pacey, and Susan Thorneloe, May 18, 1994.
BFI has five existing projects, three U.S. reciprocating engine (RIC)
projects, a U.S. pipeline quality project, and a gas turbine project at
the Packington Estates Landfill in the U.K. Gas turbines are planned
for four future U.S. installations using combined cycle, heat recovery
steam generators with turbines. The first may be operational by January
1, 1996. Several projects have a nearby industrial customer, which may
provide an opportunity for a potential boiler customer. Another 12 U.S.
installations and one Canadian installation are planned for the future
using RIC engines.
At smaller plants the cost is relatively high and thus a barrier; on
larger projects the cost may be spread more easily. In some cases the •
utilities work very well with us. It is an internal management decision
or policy on how easy or difficult they elect to be in regard to LFG
projects. One utility gave us an interconnect estimate and said this is
it for the interconnect. We felt the cost estimate was high and hired a
local engineer familiar with interconnects. We successfully argued for
a lower cost; this did not require much work because the utility
negotiated reasonably. The utility did not want to do much work on our
behalf but were willing to listen if we did the work. A few other
experiences with interconnect costs have been more difficult. Our range
of interconnect cost is from $60,000 to $600,000 for 3 to 12 MW of
capacity respectively.
Utilities
The time and degree of caution the utilities have in working on your
project depends on the utility i One common thread is that they want to
do it right and time the interconnect to coincide with the contract
start date. This can be troublesome because you would like to have it
done early so you can get the plant running earlier to get the bugs out
of the system.
We identify utilities in States where there is a PUC or legislative
requirement to buy renewable power, for example, Michigan and Illinois
or where environmental externalities are considered by the utility in
determining avoided costs, such as Massachusetts.
Wheeling
The Federal Energy Act of 1992 (October) provides the requirement for
the utilities to wheel the electricity to wholesale customers. If we
wanted to wheel say through Houston Lighting & Power, to some municipal
utility on the fringe of the service area we now have a reason to be
heard which we didn't have before. They can still set their own rate
although there are some suggested wheeling rate ranges set by the State
PUC. This is similar to the avoided cost program where they are to
determine how much it cost them to transmit the power and that is what
they would charge someone. Wholesale wheeling disputes have to go
through FERC, retail wheeling is something the state PUC's have the
authority to do. If the wheeling costs were on a realistic cost basis
it would probably open up some opportunities for us.
Most utilities have plenty of capacity today so their contract buy-back
rate does not include a capacity payment. Very few projects are getting
done because the avoided cost is too low. But almost every one of these
utilities will eventually need capacity and have a higher avoided cost.
In a span of 20 years the kWh price may go to 7-8 cents. If a utility
were willing to net-present-value that back and levelize some payments,
you would see a lot more projects. You would have a levelized payment in
the early years which would help us get financing and justify the
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project. In later years when the project is paid for and you are
working off avoided energy at your plant, pricing doesn't have to
escalate.
A barrier for a third party developer is that to be a Qualified Facility
(QF) you can burn no more than 25% natural gas, annually. In states
that have special LFG incentives, there is a requirement that you have
to maintain the QF status. So if you have a 20 year contract, you have
to maintain the QF status or you are in default. Obviously, it is very
difficult to predict 20 year gas yields.
If the utilities would allow you to reduce your capacity over time, it
would be helpful. Contract flexibility would result in an increase in
the number of LFG projects financed and brought on line.
One thing that would certainly help projects would be if it were
possible to wheel (retail basis) power. Unlike the energy act of 1992
which requires them to wheel for wholesaling there is no requirement for
retailing. Industrial customers are paying over 8 cent per kwh in many
areas and could benefit from retail wheeling by having lower operating
costs which would mean lower costs to the consumer for their products.
BFI is looking for between 5-6 cents/kw to make these projects viable.
A great difficulty is the attitude of the various air
agencies/authorities. There seems to be no consideration or forgiveness
for the fact that the gas will be generated regardless of whether there
will be an energy project or not and it is going to have to be flared.
A lot of States are talking about offsets.
So far we have not seen an increase in capital, or operating, costs as a
consequence of air board/agency requirements. There has been discussion
of SCF early in the process but BFI has been able to produce certain
vendor documentation stating that catalytic converters don't work.
One environmental barrier which has been raised is electromagnetic
fields. We have been able to deferid this by bringing in some experts
who testify the phenomenon is related to the amount of power which is
being transmitted and the transmission line configuration. This has
only been raised once. We analyzed EMF measurements in a field prior to
any development, and projected what they would be after development.
This demonstrated our project had no impact.
al Externalities
When a utility calculates their avoided costs, they should consider ALL
costs of generation, including pollution. LFG projects have lower SO2
and NOX emissions than comparable coal burning facilities and natural
gas plants (if you consider you will be eliminating emissions from the
flare) . Additionally, there is no ash disposal resulting from LFG
projects as there is in coal plants or municipal solid waste to energy
plants. These social costs can and should be monetized to reflect costs
of power generation. Renewable projects, of all sorts, could benefit
from this levelized playing field.
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INTERVIEW 3; ENERGY TACTICS. INC. (ETI)
Present: S. Drake, J. Pacey, and S. Thorneloe, May 18, 1994.
Barriers may not be the right word; perhaps hurdle would be a better
term. "We have never faced an insurmountable barrier, we face many
hurdles."
ETI's projects are all electrical using RIC engines. We are considering
using an external combustion engine at a site in NJ; this will be a
steam plant that may go forward next April. ETI provides all aspects of
project development. We will obtain permits, design the installation,
and perform operation and maintenance (O&M) activities. O'Brien does
the same. We will do O&M separately, and prefer to do O&M with ETI
designed systems.
Air Permitting Concerns
A problem with the air regulatory agencies in New York and possibly
other States is that there are no guidelines or even rules of thumb.
The problem is that each application is reviewed individually and
decided upon individually by the area air board. If we submit a plan to
the New York State Air Board we would not know that a certain emission
limit would be accepted from one project to the next. New York has a
number of independent Air Boards which answer to Albany (similar to the
California system). Albany will only get involved if the permit
submitter is totally frustrated, or maybe missed the deadline. This
creates a good deal of delay time during which we cannot even go to a
financing source and say we are going to build a project, because we do
not have the permits. We cannot satisfy the lender that we will obtain
the air permits as there is no State guideline or letter of intent to
accept the design; we have nothing to show that we almost have a permit
approval and almost have a done deal. There is a big question mark from
a lenders standpoint as to whether the Air Board permit will be
attained. Lenders don't know that permits are basically tied up before
they get serious about the project.
Permit timing includes up to 45 days for permit review and notification
as to whether the application is complete, or not. This can cause an
unnecessary delay, which happened to us at Oceanside. Luckily, the
financing for this project was coming from close associates who allowed
us to start construction before the permit was in our hands. Here was a
case where we were way ahead of the Air Board and they had exceeded the
response time, so we wrote to Albany and said we were being delayed.
Albany can decide the permit looks complete and instruct the Air Board
to notify ETI thereof, or they can say that the permit is incomplete.
That gets them off the hook and they turn it back to us and we start the
whole clock again. In this case they took the safe alternative — the
permit is not complete. The matter was resolved quickly after that, but
you can imagine how that can upset the developers and/or lenders. The
time for their responding - in this case they have a definite guideline
how soon they must respond, but if the response is negative you are back
at the starting gate again. That time took well over 3 months to get
the permit in our hands. If a simple set of guidelines were put forth
by the DEC anybody should be able to review a project submittal and
determine if the project as proposed is going to be acceptable.
Even if various districts (in New York) have greater needs for
restrictions, or requirements, they should be able to codify, or develop
specifics so the developers have guidelines. They should be able to
give us a chance to assess our approach and give comfort to lenders and
project participants. If anything the current approach is getting
worse. We find the same issue in other states. We had a New Jersey
case where we took over an O'Brien project where O'Brien wanted us to
come in and start operating. But they did not have an operating permit
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at the time, this caused uneasiness. We did have O'Brien's guarantees
that the permit issue would be resolved but that is all we had to go on.
The Air Board conditions and requirements have not yet caused a
significant increase in equipment capital or operating costs. We have
not found it too costly to comply and that environmental opposition is
not too high. Dealing with different Agencies is not considered a
significant hurdle, maybe even a benefit. The bureaucracy is not too
large it is just disorganized.
Interconnects/Utilities
We pay a lot on the interconnects. When we did our first job at
Smithtown East (1 MW) it was the first LILCO (utility) project as well.
It was a grass roots cooperation from the working people that made it
possible to bring the project on-line in that short period of time. The
intertie cost for this project was about $20,000. Interconnect costs
have steadily risen since that time. The total interconnect cost at
Hempstead was $625,000 and that was a 4 MW facility. While costs have
increased the service is still professional. The people in the
utilities who interface with us have never been a problem. There may be
bad utility policies, but not people with bad attitudes. Interconnects
do take too long to obtain. You don't know what it will cost and you
started on a project with a big unknown - the interconnect cost.
Financ incr
ETI partners handle the financial arrangements for the projects. A lot
of ETI's projects are funded on a recourse basis, which has its limits.
Some associates can only obligate a limited amount per project. Funding
sources are varied, but because the projects are of a recourse type it
means that the people backing the projects can only obligate a certain
amount of their wealth. For ETI's part the deals include a percentage
of the project. Only one project is entirely in ETI's name,
(Hempstead) . It is of the recourse variety where it is backed entirely
.by Rick Rose.
ETI has gone the nonrecourse route; there are a surprising number of
caveats and restrictions involved with this approach. Somebody starting
from scratch should expect similar difficulty.
Only one place where we had a tax issue. Onandaga landfill was assessed
a tax similar to the tax applied on natural gas well heads.
Contracts are restrictive and capacity and equipment limitations have
given ETI difficulties.
INTERVIEW 4; GRANGER RENEWABLE RESOURCES
Present: R. Nuerenberg, J. Pacey, and S. Thorneloe, May 18, 1994.
Granger development has been limited to Michigan, however we are now
considering other states, primarily in the midwest. We have in-house
planning, design construction and operations capability. This gives us
a turn-key potential, although our target market has not been truly
turn-key. We will develop a project with the posture of wanting to own,
or have a large position in it, and preferably be the operator. We have
several future projects where we will be designer and operator, but a
minority partner in the overall project.
Granger plants are not real large; using Caterpillar 3516 engines,
ranging from 2 to 6 engines per plant. We are responsible for 5 engine
plants today and 1 medium BTU plant owning all but one of these. We
have signed contracts to do 4 more by 1996.
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Most of our development experiences have been pleasant with relatively
few difficulties. Experience is very helpful in addressing new
opportunities.
Boiler Pro-iect
Our one boiler project, Motorwheel, had a number of minor hurdles:
• Right-of-way was difficult but obtainable; primarily because
most of the pipeline followed a railway. The railroad wanted
particular types of construction and materials used (steel
pipe), which resulted in a larger project cost. If the user had
been further away, or if the user could not have used all the
LFG we had around the clock, we would not have done the project.
This project was built in 1984-85 (the first LFG plant in
Michigan) .
Client Education; the client was initially concerned with:
• boiler emissions,
• operational problems,
• boiler corrosion,
• scale buildup in tubes,
• reliability of LFG supply.
The project was part of the larger landfill operation. Therefore,
interruptions were not as critical to a business schedule than if the
LFG-use activity were the only activity. The user would probably
believe he would need approval from an air board for permission to use
LFG - it might be necessary to add new discharge conditions. Therefore,
the user will initially have a reluctance to consider LFG use. With the
new CAA standards coming, the users will be more inclined to stay with
what they know and what they have and will be reluctant to change,
making medium BTU projects more difficult to develop.
Electrical Projects
During the engineering and construction of our sites, the utility has
been cooperative and accessible. Michigan has "Public Act 2" which
requires utilities to purchase a certain amount of their scheduled
capacity increase to their system from solid waste and hydro projects.
All Granger projects are Act 2 projects. In Michigan, if we had not had
Act 2 we may have only one to two projects instead of our current five,
with four under way. The Act provides a price floor on the rate
structure and facilitates getting the Power Sales contract.
Two difficulties with interconnects:
• costs are high (sometimes with uncertain justification) and
• interconnect decisions and cost are changeable.
In one case the original interconnect cost was about $380,000 and we
experienced a $125,000 increase midway into the project. Fortunately
this was on a fairly large project that could absorb the increase. If
it had been a two to three engine plant it would probably have killed
the project. There is a concern in fighting these adjustments because
it might create a precedent where the utilities will always overestimate
so as not to have to defend subsequent design additions or policy
changes, which incur more costs. The only method a developer has is to
audit the actual costs and make sure they are real .
One issue we have discussed with the utilities is allowing the developer
to purchase big ticket items to control the rather large markup in
purchasing from a vendor. When utilities use an independent contractor
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they do not necessarily go to a competitive bid. They allow a number of
contractors to bid on their contracts and assign the work.
In our experience interconnect costs range from $50,000 to $530,000,
(2.4 to 4.8 MW). The time spent on the interconnect work by a utility
that knows us is usually reasonable, although somewhat lengthy. When we
work with new utilities that don't know us, we expect a time-frame in
excess of 6 months. This is too lengthy and is thus a barrier. When we
see a $500,000 interconnect cost, we question our approach and the
utilities allocation. We obtain expert advice on the electric utility
interconnect cost and review. We believe we need this expertise on such
projects.
Michigan utilities are concerned about wheeling power. There isn't any
kind of wheeling regulation in Michigan, except among utilities. If we
were to get involved, we believe the charges would be so excessive that
they would probably not support a project.
Our cost to move a project forward (excluding extraction system and new
CAA implications) is about 5 cents/kwh. This would apply to long term
medium size projects. Short term or large projects could be developed
at a slightly lower utility rate.
Taxation/Royalties/Fees
Our Michigan projects are exempt from severance and sales tax.
Regulation
We had one experience that involved a 2-year court battle. A local
government chose to take issue with the exemption clause in the Act that
removed this type of landfill activity from local zoning review. We
actually had the plant up and constructed during the court battle.
Fortunately enough the judge allowed us to operate under certain
operational constraints but nonetheless it was under court sanction and
court review. What would have been very helpful would have been for EPA
to say that this is a technology which is an acceptable method for
handling LFG. They wanted us to follow the solid waste siting process
similar to the steps in siting a landfill since we were building the
system on a permitted landfill. That type of permitting would be very
expensive and we would have wound up with a rather phenomenal condensate
handling system and treatment plant and some rather exotic air pollution
controls. There must be a .very clear indication or statement in the
forthcoming CAA that certain technologies are acceptable for LFG
utilization. If this does not happen, then the local unit of government
may assume control and project development becomes more uncertain.
Another landfill organization has been arranging to pay host community
fees to the Township. This has happened through several different
companies so far. They are paying a tax or host community fee on the
revenue of the gas, some on the revenue of the electricity. When
electrical projects require these kind of undefined costs, it will
impede development. In essence, a large project may be able to afford
some community benefits, a small project may not.
Air permits
Historically, our projects have been able to exempt State air permitting
based on their size and engine type. More recent projects have begun to
run into some permitting difficulties including: uncertainty,
inconsistency, and lengthy reviews. Although a concern, it at present,
has not hindered development.
Financing
Financing can be difficult. The last project financed required
signatures for 62 documents. Financing takes about 4-5 months of
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intense discussion, negotiation, etc. If I have one contract, as a
minimum I would probably put a minimum of 20 hours of time on it myself
and probably 5 hours of attorney time. Now multiply that by 62; that's
a lot of dollars.
Guarantees required by lenders can be scary. Banks in general are very
skittish about financing LFG projects without a lot of attachments to
your other assets. While we work through banks, other avenues are
opening up. Some will take 100% of the financing for a large equity
share. Several of our projects have been funded internally.
Condensate
Condensate is easily misunderstood, more from the technology side than
the regulatory side. In Michigan condensate may be discharged into the
leachate management system. It cannot be returned directly to the
refuse without a permit. We can return directly into a leachate
collection pipe. This has been a real advantage in Michigan. It is
always an issue in obtaining permits. Condensate was a major focal
point in the court case that dragged on for two years (mentioned above).
We tested the condensate and reports indicated the condensate was of
lesser strength than the leachate. The equipment process stream at an
electrical project dictates the amount and character of the condensate.
Granger's design does involve refrigeration and thus produces large
volumes of condensate.
INTERVIEW 5; RUST ENVIRONMENT AND INFRASTRUCTURE/WASTE MANAGEMENT OF
NORTH AMERICA
Present: C. Andersen, M. Doom, J. Pacey, and S. Thorneloe, May 16,
1994.
WMNA's most recent projects use the RIC engines, although they also have
27 turbines in operation. They work with Caterpillar and have just
accepted the Cat 3600.
Utilities
You will see more power production by independents in the future than by
the utilities. Some of the utilities have reasonably well developed
guidelines on interconnect- and standard contracts; they have been
through it several times (LILCO and Pennsylvania 'Power & Light). Other
utilities have not been through it and quite often decisions have to go
all the way to the top. This slows things down and adds more risk to
the developer. We haven't had a bad reaction from utility staff. Our
structure is such that we do the permitting and the negotiations with
the utility simultaneously. We don't have many projects that were
negotiated and then were not built.
We have had a number of conditions where we negotiate our expansion up
front, but always with a limit on the capacity established in the
contract. In other cases, when we are in a position to ask for an
expansion, the utilities typically want to look at a brand new contract;
avoided costs have gone down, therefore we have changed market
conditions.
All utilities are looking at the deregulation issue. They are trying to
protect their interest as best they can. As a result we see that
avoided costs have gone down. For example, we have a contract with
Philadelphia Electric Company; we signed a contract with them in 1987.
We were getting 4 cents/kw which was lowered to 3 cents/kw in 1989.
Today we would be offered 2.8 cents/kw. There is no capacity with this
contract. WMNA can do a project for 2.8 cents/kw because WMNA owns the
gas, owns the compliance costs and therefore when you start offsetting
those costs versus the revenue stream you can justify a cost.
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Usually it takes a certain amount of savvy and sophistication to work
with the utilities on this issue. You have to keep their eyes open and
know your options. A project we are building in Danville, Indiana right
now -with PSOF Indiana - a good company - but as originally conceived
they gave us an interconnect cost estimate of $225 ,000, and as we got
further into negotiation the cost jumped to $368,000. There are
utilities out there that try to get in the way, but I think they are
just trying to be conservative and the view is that the developer is
going to have to pay the cost, consequently the cost is up. Our
cheapest interconnect is $10,000 and our most expensive is about
$1,500,000.
Air Permitting/Environmental Concerns
Greene Valley landfill, DuPage County, IL. This county is a
nonattainment area for NOX. We had attempted to permit a turbine plant
there. One of the problems (not only in IL) is that the States are
still formulating how they are going to meet their targets, while the
NSPS and the Ambient Air Quality Guidelines have been out for some time.
In IL there has not been a complete inventory of NOX emissions and so
there will not be any information on offsets available until 1997.
The flare that was installed was not viewed as an offset source and the
limit for a major source was only 25 tons/year. This is equal to about
one turbine or just over one engine worth of LFG. The landfill is
currently producing about 6 million cubic feet of LFG per day or 3
turbines worth of power, and ultimately will be producing about 12
million cubic feet of LFG per day. You are dealing with a State that
hasn't decided how they will meet their guidelines; any source is viewed
with great suspicion, making any discussion very difficult. The project
is currently on hold. The old utility flare was permitted for low gas
flow and high emissions. It took us 9 months to get the permit to put
in two new utility flares with lower permitted emissions (better
emission control and destruction efficiency) .
Permitting costs vary depending upon the state and area. We would
expect 6 months for permitting.
There hasn't been much environmental opposition, but always some routine
concerns. If properly addressed, you may actually get support.
Education is important. Noise is a fairly significant local concern.
We always have found that with our standard design we have noise data.
We have people visit our plant sites, this helps defray some of the
concerns. We have not yet had the noise issue stop one of our projects,
we have 'always found a suitable solution.
Condensate
We look at condensate similar to leachate. If the site has reasonable
disposal cost then condensate is combined with the leachate and not
really a problem. I would say that our sites probably pay less than
$10,000 per year to get rid of condensate. On the turbines you have the
issue of the hydrocarbons that fall out due to the high compression
pressure. They can certainly be a concern as it can be classified as a
hazardous waste generator. Unfortunately for Chemical Waste Management,
Inc. a lot of those costs have gone down in the last several years.
At some projects we pay property taxes, at others we are exempt. Taxes
can be a significant item, you could be talking $50,000 - $100, 000/year
for taxes .
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Additional Impediments
One of the big impediments is the fragmented status of solid waste
management — lots of landfills, many with a several owners. You have
the disadvantage on the landfill side, if you have the same
fragmentation on the development side it will be difficult to get a
significant number of projects done. There are a lot of people that are
not going to wait until someone forces them to be in compliance before
they do anything.
The education effort for people to get familiar with the business is
extremely large. Example - We were asked to quote on the design and
construction and start-up of a project by the owner of a landfill. The
use was as fuel to a cement kiln, a near perfect use, a fairly simple
project but a fairly long pipeline. We put in a $900,000 bid for the
project, start to finish. Another firm quoted $350,000 to do the whole
project. From our standpoint it would probably buy the compressor skid,
but not much more. How do you convince an owner that something is
seriously wrong.
INTERVIEW 6; LAIDLAW
Present: G. Jansen, J. Pacey, and S. Thorneloe, May 25, 1994.
Permitting/Environmental Concerns
I (Jansen) spend half my time on regulatory issues currently; items such
as retrofits, changes in rules and regulations from AQMD's, regulation
changes from RWQCB's (now we can't put condensate back into the landfill
- can add $8,000 to $10,000/month for condensate management), and EPA
changes in rules and regulations.
It may take two to three years to take a project from concept to
actually getting the building permits and to where we can start buying
equipment and start the project. The most difficult items are the
permits related to air regulations.
It has gotten a lot worse over the past few years. Our initial projects
could be put together and permitted within one year (1982 - 1983 time
period). Recently it took over 18 months to obtain a gas flare permit
for a site in Massachusetts. It took one year to receive an air quality
permit for a reciprocating 1C engine project.
Getting a permit can be a major problem. For example in CA we have been
faced with AB 2588, Title 5, Rule 834, 436.1 for H2S, 1150.1 for LFG
retrofits -for NOx reduction, and the RECLAIM program. All add
significant costs that, were not included in project evaluations. It is
impossible to predict what Air Boards will require. Nonattainment areas
are major problem areas in terms of trying to regulate stationary
emissions to the point where they can be in compliance with State and
EPA regulations.
CA Rule 1150.1 of the SCAQMB requires integrated surface monitoring
where you walk 10,000 square foot grids and then take Tevlar bag samples
for laboratory analysis. To do a large landfill monthly monitoring, as
required by the original rule could cost $70,000. Dioxin has never been
required, although under Rule AB2588 there are about 250 compounds you
have to monitor.
There can also be conflicting requirements. For example, in San Diego
the RWQCB said that once a final cover is in position on a landfill,
nobody can access the wellheads. Air quality said this was unacceptable
to them because you have to able to make repairs. This occurred at San
Marcos landfill where one landfill was capped and the County wanted
another permit to overlay the completed landfill by vertical expansion.
Laidlaw wanted to extend the gas wells vertically through the existing
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cap which contained a synthetic membrane. The water board wanted
lateral extensions at the edges instead of vertical risings. They had
overlooked settlements. Air quality saved the situation by insisting
vertical rising of the gas wells was necessary. This took a 3-4 month
period to accomplish. • This demonstrates the individual agency bias,
with little if any coordination for the good of the project, and/or
practicality.
Case History: The New England Power Issue
Another barrier was created by the PUC in RI. In spring 1994, the Rhode
Island PUC ruled that the utilities would be paying too much for LFG
generated electricity. We have tried to get together with all of the
impacted developers and try to come up with a methodology to develop
projects in the New England Power (NEP) jurisdiction. Of the maybe five
projects currently involved in this issue, several are LFG projects.
(Laidlaw project at Plainville, MA; BFI project at Randolph, MA; Bob
Hawthorne and Ed Barie from Genesis (a waste heat project) at Johnston,
RI; a Soncook project in Nashua NH; and Philips, a landfill project
located in Barre, MA). We have all hired the same attorney. RI took 23%
of the power and NH took 3%. The MA PUC is now deciding whether the
commission will support LFG projects. When New England Power came back
with the proviso that all three PUCs needed to ratify the contract, the
negotiations broke down.
NH staff rejected all LFG projects, but not the others, saying that the
NEP was paying too much for the power. The LFG projects were not
demonstrable projects because it was not new technology and LFG had to be
collected and flared anyway so the projects were not doing anything for
the environment. All LFG projects agreed to pay an up-front payment which
was the net present value of the stream of payments over and above the
avoided cost so that the rate payers would be indifferent. Because the
avoided cost in NH was only 3% of the total power, we agreed to a single
up front payment which represented the overpayment over avoided cost.
Then it came to RI which rejected all alternative energy applicants, not
just the LFG projects. They said NEP was paying too much for the power
and the rate payers would be asked to subsidize these projects. We have
worked out a program of levelized payments to RI so the rate payers will
not be subsidizing the projects. In RI we would agree to a refund of
0.17 cents per generated kwh.
Before MA staff ruled NEP withdrew all projects from before the PUC. All
of this took place in early June because NEP was filing new avoided costs
which apparently are about 15% below the current rate of 2.7 cents/kwh.
NEP is claiming that their new avoided cost is going to be about 2.2
cents/kwh. That means that any project that comes before a PUC
commission will be compared to that 2.2 cents/kwh rate. One price bid was
5.4 cents/kwh. With the revised structure we propose now it is about 4.5
cents/kwh. We can't do it for 2.2 cents/kwh. Our operating costs are
over 2.5 cents/kwh.
This NEP issue has delayed our project schedule to date by about 1.5
years. NEP could have said the opposition from the PUCs killed the
projects and they and the PUCs would be done with the projects. NEP
would still have garnered all of the favorable public relations value
from their Green RFP. All of our project sponsors got together and
threatened to sue NEP for breach of contract. That is the reason they
came back to the table. The breach of contract issue was that we found
out that NEP pulled the contract application from MA only hours before MA
was about to approve it. The other issue that NEP was concerned with was
wheeling. That is the real reason- they preferred that all these
projects disappear at that point. They are hiding behind the PUC issues.
The real reason is that the NEP believes they will be forced to pay the
higher rate . Avoided costs in that area are about 2. 75 cents/kw and
the feeling was that the new proposed rates will be about 2.0 cents/kw/.
The positive is that NEP seeing the corner it was in was willing to
continue negotiations with the project sponsors to generate a contract.
They could have said that is the breaks of the game and sue us.
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In the case of NEP, NH was only receiving 3% or less of the total power
from these projects and so the impact of the projects on the rate payers
would have been negligible . Out of the many hundreds of MWs, this whole
activity related to LFG projects was less than 36 mw, very small
potential increase. The point was that NH staff felt that this was the
edge of a wedge and if they allowed some increase in avoided cost then
where would you hold the line. They did not see this as new technology.
They felt that flares had to be put in anyway as a control requirement.
the fact that an electrical project was involved was of no significance.
NH was the first on to reject the projects. All project sponsors
countered by agreeing to pay up front the net present value (NPV) over
payments. RI cancelled all projects. All agreed to take a lesser
price. This left only MA which was where the bulk of the power was going
anyway. Out of this the MA PUC was the most friendly to these projects.
The staff and commission had already agreed. , and it would have been
published within hours of NEP cancelling their application.
Levelized contract are in the same category. Nobody will get 5 cents/kw.
The only way we can do a project is to allocate some of our post closure
costs at that particular landfill. We do not have a royalty in our
project because it is a company landfill. Our company landfill group has
agreed to allocate some of the post closure costs to the revenue from my
Ifg project, so I can now accept something less the 5 cents/kw. Neither
is the extraction system cost allocated to this project, it is a cost to
the landfill. This is considered a special project and should not be
construed that this is a new pricing format for LFG projects. However,
industry should recognize that this is how projects are done today. We
are taking every advantage available in order to do these projects.
I am about to do the same thing for the Cedar Hills project in Seattle.
I am also working with PugetPower (PP). They are now saying that the PUC
is second guessing decisions that PP made 10 years ago. Some of those
decisions are now being revisited by the PUC with arguments that the
utility paid too much for the power. PP is now skittish and this project
is going to be 15 to 20 mw. We have made it very clear that if the
original proposal we gave to PP can be consummated then we have a
project. We have just commenced this discussion. Politically this
project is going to be at the mercy of the PUC. They have mandated to
lower rates.
Interconnects
Interconnects always need negotiation. It has occurred often that the
utilities gave us one estimate and the final estimate came in at double the
cost. In CA a utility came back to us 6 years after the interconnect and is
demanding payment of additional interconnect cost but without any backup of
the claim. This is a continued aggravation once the project is on-line.
Condensate
A lot of landfills will not accept the condensate. Where the landfill owner
is not a part of the LFG project, it is not always easy, or acceptable to
discharge the condensate back into the landfill leachate management system.
BFI claimed that the EPA prevented them from accepting the condensate back
into their system at the Newby Island landfill as a force majeure item. They
were referring to the Subtitle D regulations.
Taxation/Royalties
Most states are interested in obtaining tax revenues. In NY they tax you on
your revenue - gross revenue earned by the facility. There is no way that a
project can ever go down in value, it can only go up. Every year the tax
increases. It is getting onerous. Hawaii uses a property tax assessment,
they exempt most everything (sales tax) but charge a fairly high possessory
interest tax which is a fairly high cost for us. .
Taxation boards are deciding that LFG is a resource, a reservoir, and if we
multiply the royalty paid to the owner times 20 years and give it a value and
call it a possessory interest, then bring it back to present value and assess
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a tax on this value. If you are paying $12,000 a year in royalty over 20
years that is $2,400,000 and the gas is taxed at say 1.5% of this value. It
is brought back to a net present value and taxed. You pay this in addition to
the personal property tax on the value of the equipment. The LFG projects now
have a cost that was not included in any of the proformas of $2,400,000, in CA
this amounts to about $36,000/year added to the project. This is based on the
property (gas reserve) . This is a major barrier because you have to add these
costs with no revenue offset. With energy prices so low, such taxation can be
the straw that breaks the project's back.
We lost two Southern California Edison bids as a result of the carbon tax
policy. If they change their policy we would bid on the capacity auctions.
At the time of the bids they refused to deduct the carbon tax. I understand
GSF bid without including the carbon tax, hoping that they would change it
later. As a result they were able to win a capacity contract. Whether or not
they can get the carbon tax overturned is a question; the utilities made it
very clear to us during prebids at So. Cal. Edison and at SDG&E that they
. intend to enforce the carbon penalty. PG&E, SCE and SDG&E have the same
attitude. There is no point in our bidding at future auctions because we end
up losing about 1.5 cents/kw just to overcome the carbon tax.
Financing
Financing is becoming a major issue as we are not developing new projects due
to the low energy price structure. The internal rate of return of around 5-6%
for these projects is extremely low which means that you can no longer
evaluate the projects on 100% financing base. Laidlaw would never fund such
projects. If we leverage projects (only use 25% equity and borrow the
balance), the return on the investment is between 10 and 14%. The problem is
that you have to finance the project off balance sheet which means non-
recourse loans. A small project of less than 5 million dollars is almost
unfinanceable. Bankers want projects above 20 million dollars. The
transactional cost kills the small project because the cost of doing a 5
million dollar project is the same as for the 20 million project.
Consequently, the institutional barrier to the project development is the very
high up-front bank fee to do the engineering studies, to do the legal
documentation, which can be a significant portion of the funds required. If
you could find mezzanine, or similar financing, you might be able to do a
project, but the cost would be several additional points on the loan. Bernie
Zahren's methodology of trying to get a line of credit from an institution and
bearing a lot of the transactional costs in-house is probably the way to do
it. Bernie has the same problem that we do in that he can't use the
production tax credit for his own account. So he needs to find a third party.
Liability
There are not many existing developers. Landfill owners will have to get very
realistic in terms of what kind of an asset they really have with LFG. If
they treat it more as a liability and the development of a project is an
offset of the liability then it is probably the right direction. There are
many landfill owners who still believe they are sitting on a gold mine.
In many instances the landfill owner, or operator, cannot slough off the
environmental liabilities to a third party. The Irvine Company tried to pass
on their LFG liability to Laidlaw at the Coyote Landfill, but the SCAQMD Board
ruled that the Irvine Company had the responsibility and what they did with a
third party contract was between the Irvine Company and the developer. Most,
landfill owners try to pass the gas liabilities off because even if they have
the total liability they at least have somebody to look to. But the SCAQMD
Rule 1150.1 clearly states 'the owner, or operator, of the landfill is
responsible."
Operating costs
Our 2.5 cents/kwh is realistic for operating costs. Others may quote lower
prices, but this is probably exclusive of the extraction system, property
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taxes, liabilities, insurance, utilities you have to buy, disposal of
condensate, catastrophic events, etc. This is probably only the cost of the
equipment. Laidlaw's price only excludes the cost of royalty payments, if
applicable. The costs are increasing dramatically now because of the air
quality retrofit rules and regulations - condensate disposal is the single
biggest issue. We are spending close to $250,000 on a pilot project to try
and solve the condensate problem, at one site. The flare program seems to be
a viable approach, but you may be incinerating a hazardous waste.
A specific CA regulation, the Hayden Bill, required the clean up of LFG before
its introduction into a pipeline. That killed all LFG to pipeline quality
projects in CA. That probably shut down the PG&E project, you can't clean the
gas economically and get rid of all the bad compounds.
INTERVIEW 7; PACIFIC ENERGY
Present: F. Wong, G. Donlou, M. Doom, J. Pacey, and S. Thorneloe, June 3,
• 1994.
t B
We have received what we thought were high interconnect estimates; for small
projects this is a problem'. The utility feels justified in their costs; they
are not noted for a low-cost approach. Landfills often tend to be in remote
rural areas and you get charged with the full cost of line extension and
capacity upgrade. We paid for new capacitors which sometimes didn't get
installed. Capital costs for interconnects range from about $20 K to $500 K
for 1-10 MW.
Utilities
Energy prices have dropped, so much that utilities do not find much good in LFG
projects. This has led to some antagonism with contract administration. This
thrust is also coming from the PUC, because the PUC does not like the relative
high cost of LFG generated electricity. Their department of rate payer
advocate is putting pressure on the utilities who in turn have no choice but
to put pressure on the Qualifying Facility (QF) . This problem will probably
get worse in the west. The electricity price is getting very competitive as
the electricity is getting to be a commodity. The price has come down so much
it is now about 2.5 cents/kwh. With the CA PUC saying they are going to be
dropping any program just to promote environmental values, it will be very
tough to develop new projects. The PUC has made the announcement that this is
the way they plan to direct utilities in CA. They will open new electricity
supply to competition and fundamentally change the electric industry and make
it competitive within a free market.
In the UK they deregulated their electric industry. The CA PUC toured the UK
as part of their process in figuring out how they wanted to develop their
policy. They have developed a somewhat similar policy approach. They have
not gone as far as saying they want to separate the generation from the
utility at this point, but for this to work it has to get to the UK
philosophy. The CA PUC has dictated a timetable when they would like to see
the new rule in place. They are talking 1996, and including retail wheeling.
If landfill projects have to compete on a level playing field in a free market
place, competing with all the other energy projects, it would not survive.
There has to be something else such as the Section 29 (PTC's). There are some
fundamental differences that make the landfill projects a higher cost producer
when it comes to power. Even with the tax credits it is tough to compete with
a large 200 MW combined cycle gas fired project right now. They are building
and selling that power for about 2.5 to 3 cents/kwh. Our O&M costs on some of
these small LFG projects exceed that before you roll in capital cost.
Wheeling could be a benefit, there are a lot of institutional things that need
to phange before you can do retail wheeling, but they are headed in that
D-29
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direction. The history has always been that utilities are opposed to doing
any kind of wheeling.
Our last project was the expansion of Otay and Oxnard. It was in 1987 when we
completed our last new project. Each new expansion negotiation is like
entering into a new contract.
Size of pro-ject
Size of project is a big issue with PEN. With limited human resources you can
only do so many projects. We found that the landfill projects take a lot of
management time; both during the development and the operation. That is a
problem because you cannot cookie cutter these projects. Even though a lot of
our plants have the same engines and same basic design; the development
process for each one is unique for that site. Operating each landfill also
has its own characteristics; this makes it tough from a human resource
allocation standpoint. Our landfill projects are the smallest energy projects
that we have in our company. When you talk about a 1 MW compared to a 30 MW
project or larger, then you spend a disproportionate amount of time for a
landfill project. The issues are significant from the scale of project and
scale of company When you talk about $200,000 of retrofit, or new
environmental regulations that could put people in jail then you have to spend
the time necessary to address and comply with the issues.
We cannot sell our power to anybody other than the utility, we cannot change
the rate for which we get paid, we simply have no control over those issues.
So when the costs are uncontrollable and we keep getting new things thrown at
us it makes you want to adjust the return required for entering into new LFG
projects. It is more of a concern for us on landfill projects then some of
the other technologies that we are involved with. It was worse when landfills
were even a hotter topic than they seem to be today; environmental concerns,
neighborhood concern, toxics. You could not even get insurance, I don't think
you can get insurance today to cover environmental damage. We are aware of
the litigation associated with landfills and it makes us nervous about getting
involved if we don't have to be. To expand an existing project you have
certain economies and you already have a liability risk so we are not getting
into new liability.
Air Permitting/Environmental Concerns
The landfill projects are heavily penalized because of C02 emissions in CA.
This killed a number of otherwise competitive LFG projects in the auction bid
process now in effect by CA utilities. The PUC gives the direction for this
structure. The landfills got penalized not only for the CO2 created in
combusting the CH4, but also by the C02 in the LFG.
PEN has very good relations with many air districts. However, some tend to be
very parochial in their view of environmental enforcement as they have a
single guiding bias, that is air quality. When you are trying to look at a
total project and total environmental compatibility, the single bias approach
is sometimes at odds with the total picture. Air people want you to put
contaminants in the water, water people want you to put it in the air, and so
on. This isn't just because we are associated with a landfill, it probably
happens with any industry.
Some air districts consider BACT on landfills to be a flare. So when you
attempt to permit a power facility they say wait a minute. When you attempt
to do a project they say it is not BACT. Air districts don't give much
thought to the fact that LFG does have various constituents in it and when you
burn off the gas, in a flare or engine, no credits are given. They don't care
what your fuel source is, they are guided by the single point discharge
assessment only. An example is H2S, it is in the gas whether it is burned, or
not. Air districts should take that into consideration - you have to do
something with the gas. The air board actually penalizes us as the BACT does
not create the H2S. The new rule 431.1 says you cannot burn any fuel that has
D-30
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more then 40 ppm of sulfur compound. It is not like we have a choice in LFG,
it must be burned.
With respect to liability, we are very sensitive to migration and odor issues.
We get heavily involved with the landfill owners whenever there is a problem,
or perceived problem. Even though we are clearly indemnified for all
migration issues. At a number of projects where we are in a populated area
and there is a school across the street, for instance, if there are any hot
probe readings, we are on the problem immediately. As soon as we get a call
or find out about it we spend the time necessary and take the action necessary
to mitigate the problem. This is not because we are contractually obligated
but it is the right thing and smart thing to do. If there is a problem
everybody will eventually get pulled into the problem. In addition there will
be risks associated with an end use project that are not necessarily
associated with the flare. A case in point is ground water contamination.
You could have underground tanks and even though they may not be leaking the
regional water board could come after you if they were to suspect that you
were a contributor of ground water contamination. You have condensate issues,
a number of things that increase liability if you are an operator, which are
different from operating a flare.
Condensate disposal
Some landfills will take the condensate with their wastewater treatment, and •
the cost of condensate handling is relatively low. Other cases exist where it
must be trucked to -disposal by a private company and costs here are up to
$1.00/gallon. Some of these are class 3 (CA) landfills. Cost of condensate
disposal can be the straw that breaks a project. In one instance we could not
get a permit from the local regional water quality control agency for
condensate disposal at the site. The trucking costs were too much and the
project was abandoned.
We have had noise issues, but only a cost issue. We have spent up to
$100,000. Many sites are in a populated areas and the cost is built in. Our
problems have been in more remote areas where we had to go back and retrofit;
the cost was not built into the original proforma.
Fj.na.nc incr
Most projects are too small for third party financing. Even to get investment
entities excited, by the time you include all the closing costs it makes the
rate unattractive. When these costs are amortized over the term and amount of
the loan, it is unattractive. The smaller the project, the more sensitive it
is to the loan costs.
Long-term power sales contracts are required by lenders. You will not have a
fixed cost stream, or you- don't know what the price stream will be in the
future; you have a very speculative proforma for loan consideration and that
makes it tough to get loan interest.
Taxation
Taxation is not necessarily a barrier. As for property taxes, a number of go-
abounds is probably normal. CA has a possessory interest that kicks in when
you are leasing something from a public entity which pays no tax. If you
lease a building from them the tax assessor says you should be paying property
taxes. The tax assessors have applied this reasoning to landfills, depending
on how they value it. The royalty on the LFG stream is what they'consider
rent and they value this as a property tax. They tax on the gas reserve,
looking at the royalty interest. The tax on the gas extraction system is
valued on the gas reserve taking a future value and bringing it back to
present worth. They consider secured, unsecured, and possessory taxes.
D-31
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APPENDIX E: AUSTRALIAN DEVELOPMENTS AND EUROPEAN EXPERIENCE
DEVELOPMENTS IN AUSTRALIA
Currently there are three active landfill gas to electricity projects in Australia generating approximately
8.5 kW. Australian interest in landfill gas end-use as a fuel was spurred during the 1980s by successful
projects in Germany, England, and the U.S. By the mid-1980s, three research projects were being
conducted in Australia.
At the Northcote landfill in Melbourne gas had been extracted from a council landfill and used to fire a small
generator to produce electricity in a demonstration project. At Tea-Tree Bully in Adelaide, research was
being conducted with landfill gas being used as a fuel to fire brick-making kilns. Another project was located
at the Merrylands landfill in Sydney. In 1987, the Victoria regional utility (SECV) announced its
Cogeneration and Renewables Incentive Plan which allowed electricity generation from landfill gas to be
economically viable. One characteristic of the program was to pay high peak hour prices 5 days per week
16 hours per day and very low payments for the off peak hours.
The City of Sunshine, northwest of Melbourne, commended studies of using landfill gas to fuel engine
generator units to produce and sell electricity to the local grid in 1986 at their Carrington tip and in 1988 at
the adjacent Hulett Street tip. In concert with GEC Alsthom (GECA), they commissioned the Hulett Street
electricity project in early 1992. This project had an installed capacity of 7.5 MW. Due to landfill gas
shortfall it has only been producing about 3 MW during peak hours. The landfill contains about 3 million
tons of waste. It is about 100 feet in average depth and has a leachate level at about mid-depth. It was
filled between the years 1978 and 1990. The engines are Ruston Model 12RK70GS, rated at 1,735 kWe.
The Eastern Refuse disposal Region (Cities of Berwick, Croydon, Dandenong, Nunawading, Ringwood, and
Shire of Sherbrooke) commenced a similar study in 1988 at their cooperative Narre-Warren landfill in
Berwick. This landfill will contain about 1.7 million tons of refuse at its completion in 1998, it averages about
100 feet in depth and is situated in an abandoned 35 acre quarry. It commenced filling in 1982 and should
be completed in 1994.
In May of 1992 Energy Developments International, Ltd. (EDIL) commissioned a power project at the Narre-
Warren landfill and in November of 1992 increased the plant capacity to 4.5 MW. The engines are
Caterpillar 3516 SITA, rated at 800 kWe nominal. They are delivering about 900 kWe per unit. EDIL also
commissioned a 1.0 MW plant in December of 1992 at the Corio Landfill near Geelong in Victoria. This
landfill opened in 1979 and will be filled in 1999. It will contain about 1.5 million tons at completion of filling
and have an average depth of about 25 feet. EDIL anticipates it will commission a power facility at the
Lucas Heights Landfill south of Sydney by mid-1994.
Australian landfill gas end-use projects suffer from low energy prices for fuel. Incentive programs are
generally required in order to foster development of these projects. The SECV incentive program in 1987
served to spur a number of studies of the landfills within this region and resulted in project activity. EDIL
has developed an ability to modularize its engine/generator sets to fit small to large project needs at very
competitive pricing. This approach should also facilitate landfill gas end-use projects.
EXPERIENCE IN THE NETHERLANDS
There are 15 landfill gas utilization schemes in the Netherlands, utilizing approximately 75x106 m3 landfill gas
per year. Seven projects use gas to generate electricity. Four projects purify the gas to pipeline quality (the
Netherlands has an extensive natural gas network), whereas in four other schemes the gas is fed to boilers.
It is expected that the number of projects will more than double by 1996, bringing the amount of utilized
landfill gas to 185x106 m3.
The following pages give an overview of landfill gas utilization activities in the Netherlands. They are taken
from a brochure entitled: "Landfill Gas in the Dutch Perspective," published in March 1994 by the Landfill
Gas Advisory Center, Utrecht, The Netherlands (Phone 31.30.316805).
E-1
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Where organic waste is dum-
ped landfill gas is formed: a
gas mixture consisting of 60
per cent methane (CH^) and
40 per cent carbon dioxide
(CO2). The uncontrolled
escape of landfill gas into the
atmosphere is detrimental to
the environment. It can be
prevented by extracting and
using landfill gas. In the
Netherlands wide experien-
ce has been acquired in this
field during the last ten
years.
Methane emissions stronglv
O .
contribute to the greenhouse
effect. At the 1992 United
Nations Conference on
Environment and Development
in Rio de Janeiro it was decided
to reduce methane emissions
considerably. Landfill gas can
play a substantial role in attai-
ning this objective. By extrac-
ting landfill gas methane emis-
sions are prevented and, if
landfill gas is subsequently used
as a source ot energy, fossil fuels
are saved. In this way emissions
of fossil carbon dioxide are also
prevented.
Landfill gas extraction is not
only good for the environment,
but it is also financially attrac-
tive. The technology applied
has been proved and a return
on investment can be achieved,
\\hereas many environmental
measures only cost money.
Because landlill gas yields
money landfill gas extraction
turns out l<> be also economi-
cally one of the most effective
measures to prevent methane
emissions and to reduce (.<)-,
-------
number ol
projects
Since the early eighties gas
has been extracted from
landfill sites in the
Netherlands. Initially, this
was done to prevent envi-
ronmental problems in the
direct vicinity of the landfill
site such as odours, damage
to vegetation and danger of
fire and explosions. Owing
to the rapidly rising energy
prices these developments
gained momentum. Energy
distribution companies took
the lead. However, due to
the fall in energy prices in
the mid-eighties interest
slackened again.
million
development of landfill gas projects
Since 1989 there has been a clear
rise in the number of landfill
gas projects and in the gas
quantities extracted in the
Netherlands. In 1993 an estima-
ted 760 million m3 of landfill
gas was formed, of which 123
Landfill Gas in the Netherlands
In practice only 50 per cent
turns out to be extractable: a
major part of the landfill gas is
formed before the extraction
system has been realised and
another part turns out not to
be effectively extractable.
From 1995 particularly the
separate collection of vegeta-
bles, fruit and garden waste as
well as a reduction in organic
waste disposal will affect landfill
gas quantities. Since landfill gas
is formed over a relatively long
period, it will be possible to
extract landfill gas far beyond
2000.
It is estimated that in the years
to come yearly 200 to 265 mil-
lion m3 of landfill gas can be
extracted.
By the end of the eighties inte-
rest in landfill gas extraction
revived, but now for reasons of
environmental protection. In
1989 the Dutch Government
drew up the National Environ-
mental Policy Plan to reduce
environmental pollution.
Energy distribution companies
took up this development with
an Environmental Action Plan
for their own sector. Due to
these developments in the
Netherlands landfill gas extrac-
tion is being integrated in the
national waste disposal policy,
on the one hand, and in the
policy of energy distribution
companies to save energy and
largely reduce the emission of
harmful substances on the
other.
million m3 was extracted and 85
million m3 was subsequently
used. In 1993 landfill gas extrac-
tion in the Netherlands led to a
fall in methane emissions to 48
ktonnes. In addition, fossil
fuels were saved by a substantial
increase in the potential of
sustainable energy.
million m3 landfill gas
% Landfill gas projects
in operation
O Land/ill gas pro/ects
in planning
O Other landfills
with gas potential
To realise a sharper increase in
the number of landfill gas pro-
jects the Landfill Gas Advisory
Centre was founded in 1992. Its
main objective is to give profes-
sional assistance in the develop-
ment of new projects. For fur-
ther information about the
Landfill Gas Advisory Centre
see page 10.
-------
projection of extractable landfill gas quantities
Landfill gas extraction
To assess the feasibility of a
project and the right dimen-
sions of the plant a correct
estimate of the quantities of
extractable landfill gas is of
major importance. In prac-
tice projections with a cer-
tain band width are made
within which the expected
gas quantities may vary.
In designing the extraction
plant it is wise to start from
the expected maximum
quantities of landfill gas. In
landfill gas extraction atten-
tion has to be paid first to
the environment.
The dimensions of the utili-
sation plant can best be
based on the expected mini-
mum quantities of landfill
gas, in which particularly
economic interests play a
role.
Given certain waste quantities
the formation of landfill gas can
hardly be influenced. However,
the total quantity of exti actable
gas can be influenced if the
extraction is started as soon as
possible.
Since the largest quantities of
landfill gas are already formed
during landfill build-up it is
important to start extracting
gas as soon as possible after or
even during dumping..This
way emissions of harmful gases
are largelv reduced and sub-
stantial financial advantages can
be gained.
In the Netherlands various
technologies are used. Broadly,
a distinction can be made into
the following technologies:
- in established landfill sites:
either surface collection or
vertical \vellssystem;
- during landfill build-up: con-
struction of either horizontal
or vertical systems.
Combinations of these tech-
nologies are also possible.
Vertical wells system
Vertical wells systems were
applied in the Netherlands in
the initial landfill gas projects.
Shortly after shut-down of the
landfill site vertical shafts'are
drilled or dug. One drawback is
that a large part of the landfill
gas has already escaped, in par-
ticular from the oldest parts of
the site. This problem can be
alleviated by building up the
site in separate sections. As
soon as a section has been com-
pleted the wells should be con-
structed. This way the interval
between waste dumping and
extraction of the gas is drastical-
K shortened.
-------
Surface collection
Surface collection systems can
be installed only after a top
cover has been applied to the
landfill body. Use can be made
of so-called collection matting
in which the gas is transported
through.narrow ducts to a few
central collection .points.
Vertical extraction system during waste dumping
Another option is to install per-
forated pipes beneath the top
cover. A disadvantage is that
such systems cannot be instal-
led until the landfill body has
settled to some extent. This
will take some years and a lot of
gas will then already have eSc,a>"'.
ped. ::"' •f.-,'f^'/-(^',-.
Vertical extraction systems are
built up while waste dumping is
in progress. Large-diameter
steel pipes are erected and in
each pipe a well shaft is placed.
The clearance between pipe and
well shaft is filled with some
coarse material like brick debris
or gravel. After a dump layer
(2-5 metre) has been completed
the steel sleeve is lifted and the
process is repeated until the
final height of the dump body
has been reached. The sleeve is
then removed. By horizontal
interconnection of the vertical
wells landfill gas extraction canr.
Horizontal extraction
The great advantage of hori-
zontal extraction is that it may
be started relatively early. The
collection pipes may be so
installed that they are not in
the way during dumping.
The wells should be adequately
protected, though. The system
would seem effective in parti-
cular on sites where dumping is
effected in layers.
-------
Utilisation of landfill gas
Landfill gas isa kind of bio-
gas that can be used in
various wavs. In the first
place it can be employed on
the landfill site itself to meet
the site's energy demands.
In many cases, however, the
extracted quantities of gas
exceed the site's energy
demand, so that opportuni-
ties for use outside the land-
fill site have to be sought. In
the Netherlands three
methodsof landfill utilisa-
tion are applied: direct com-
bustion, electricity genera-
tion — by means of CHP
(Combined Heat and Power)
or otherwise— and upgrading
to natural gas quality.
Total: 85 nyilliorrm3
Direct combustion
Raw landfill gas can be supplied
direct to an industrial consu-
mer, either for heating purpo-
ses or for use in some industrial
process. This way of utilising
the gas offers the highest degree
of efficiency, provided offtake is
continuous.
This option is used in only a few
Dutch landfill gas projects.
Often the distance between
landfill site and consumer is too
Brick kiln
large or the consumer cannot
guarantee continuity of offtake.
In power generation or upgra-
ding to natural gas quality such
continuity is indeed guaran-
teed, which makes a landfill gas
project far more attractive eco-
nomically. Moreover. Dutch
energy distribution companies
are prepared to invest in these
options.
Values for landfill gas
Kind of energy/destination
. 5 10 .15 20 25
Dutch cents / cubit meter landfill gas
-------
Electricity generation
Landfill gas can be used to gene-
rate electricity by means of a
gas engine or gas turbine. The
electricity produced may be
used on site or supplied to the
public grid. So far only the gas
engine option has been used in
the Netherlands for power
generation from landfill gas. A
gas engine offers high flexibility
of use and is fast to install and
move.
In gas engines a lot of heat is
discharged by way of the cool-
ing water. This heat amounts
to no less than 30 per cent of
the energy supplied by means
of the landfill gas. To improve
the efficiency of the installation
combined heat and power pro-
duction (CHP) is applied: both
the generated electricity and
the released heat are utilised.
Since transporting the heat
would result in substantial los-
ses, it is more attractive to
transport the landfill gas and
locate the CHP installation at
the place where the heat is nee-
ded, such as buildings or horti-
cultural greenhouses. In 1993
30% of the landfill gas projects
in the Netherlands featured
electricity generation by means
of CHP plant. The Dutch
government even grant subsi-
dies for CHP installations.
Upgrading to natural gas quality
The third method of utilising
the extracted landfill gas is to
upgrade it to natural gas quali-
ty. In upgrading, the carbon
dioxide is removed from the
landfill gas. Moreover, the gas is
dried and all kinds of impurities
are removed. Carbon dioxide
removal technologies are get-
ting increasingly advanced and
less expensive. Three techni-
ques are currently in use:
water-wash process, pressure
swing adsorption and
membrane separation.
Water-wash process
In the water-wash process car-
bon dioxide removal is effected
by means of a physical solution
in water. This is the oldest tech-
nique, which is applied in the
Netherlands in one installation.
Meanwhile more advanced and
less expensive methods are avai-
lable.
Water-wash process
sulphur
removal
CO2 removal
(water wash)
-------
Pressure swing adsorption
sulphur CI-F
removal removal
CO2 removal
& drying (PSA)
CO,
Pressure swing adsorption
The pressure swing adsorption
technology was developed
during the sixties and seventies.
It is based on differences in ad-
sorption rate and molecule size.
By the end of the eighties this
technology became available
for CO2 and CH^ separation.
The carbon dioxide is physically
adsorbed to active carbon. In
the Netherlands two landfill gas
projects featuring PSA techno-
logy are in operation.
Membrane separation
Membrane separation is the
most recent technology. CO2
and CH^ separation takes place
on the basis of molecule size.
Membrane installations are
small in relation to the other
types of installations and they
may be designed as movable
units. Currently, three mem-
brane installations are in use in
Dutch landfill gas projects.
In some cases (part of) the
extracted landfill gas is flared.
For instance because there is no
utilisation plant available (yet)
or because it is out of operation.
It may also happen that more
gas is extracted than the utilisa-
tion installation can handle.
If the latter is a structural phe-
nomenon, the utilisation plant
should be extended. Anyhow,
flaring leads to
a reduction
in methane
lyiernbrame separation .
mmm
E-8
-------
At the initiative of the asso-
ciation of energy distribu-
tion companies EnergieNed,
the waste processing associa-
tion WAV and the Nether-
lands Agency of Energy and
the Environment NOVEM
the Adviescentrum Stortgas
(Landfill Gas Advisory
Centre) was founded in 1992.
The advisory centre assists
them in drawing up new pro-
jects. Moreover, the bureau is a
place for transferring knowled-
ge and experience gained in the
operation of landfill gas pro-
jects. The advisory centre deals
with both technical/economic
and management/legal issues.
Landfill Gas Advisory Centre
for promotion and support
The initiators' objective was to
implement a large number of
landfill gas projects in a short
time so as to boost the quanti-
ties of landfill gas extracted and
utilised. The advisory centre
was'set up as an independent
bureau to be operational for a
period of three years providing
information and advice about
the setting up and management
of landfill gas projects. Firstly,
the Landfill Gas Advisory
Centre focuses on the parties
directly involved: the Dutch
landfill site owners and energy
distribution
companies.
Project assistance
An important task of the
Landfill Gas Advisory Centre is
to give advice on the prepara-
tion, realization and operation
of projects. Partly, this is done
at the request of an energy dis-
tribution company or landfill
site owner. However, the advis-
ory centre itself also takes the
initiative. In the latter case it
carries out a preliminary in-
vestigation to assess (broadly)
the feasibility of a project.
Landfill Gas Contact Group
The Landfill Gas Advisory
Centre took the initiative to
found a Landfill Gas Contact
Group in which, meanwhile, a
large number of energy distri-
bution companies and landfill
site operators participate.
The Group's aim is to exchange
knowledge and experience
between current and future
owners of landfill gas projects.
Information
Information plays a prominent
role in the activities of the
advisory centre. The Landfill
Gas Info newsletter is regularly
published and the advisory
centre organises public infor-
mation meetings and work-
shops. The bureau itself provi-
des a wide variety of
publications and staff members
regularly write articles for
scientific journals. This way the
advisory centre meets a great
demand for independent and
objective information.
Knowledge acquisition
The activities of the Landfill Gas
Advisory Centre partly focus
on the acquisition of know-
ledge about landfill gas projects.
The staff members of the advis-
ory centre collect information
and sit on various committees.
On the basis of the available
knowledge the advisory centre
is the oracle for all parties con-
cerned. The Dutch govern-
ment and organisations in the
above line of industry use the
information of the Landfill Gas
Advisory Centre to formulate
their policies.
ADVIESCENTRUM
STORTGAS
E-9
-------
Landfill gas demonstration projects in the Netherlands
Main supplier
Consultant
site: 't Kikkerink
(Ambt-Delden)
capacity: UOOnrVhr
application; steam boiler
since- 19S3
site: liavel-Dorst
capacily: 1,000 mj/hr
application: hrik kiln
since. I9S5
.site: Spinder (Tilburg)
capacity: 2,000 m '/hr
application: upgrading to
natural gj,s quality
(water wash)
since: I9S7
site: VAM-\Vijster
capacitv: 1.1,50 nr'/hr
application: upgrading to
natural gas quality
(PSA)
since: 1989
site. Gulbcrgen
(Nuenen)
capacity; 1.300 m^/hr
application: upgrading to
natural tjas qualitv
(PSA)
since: 1990
sire: Vasse
capaiTitv: 375 itv'/lir
application: upgrading to
natural gas quality
(membranes)
since: 1991
site: Kragge I + I! (Bergen
op Zoom)
capacity: MOOmJ/hr
application: combined heat and
power in green-
houses
since: 1993
site: Wepcrpolder
capacity: 400 mA/hr
application: upgrading to
natural gas quality
(membranes)
since: 199-1
Other Addresses
Landfill Gas Advisory Centre
(Advicscenlrum Slortgas)
P.O. Box 19.100
3.501 Dl-l UTRECHT
COCAS N.V.
P.O. Box 71
7601) AI.MEI.O
tel. +31 5490.1666ft
Grontmij. N.V.
P.O. Box 20.1
.1730 AF DE HILT
icl. +31 30207911
SMB-Stortgas b.v.
c/o P.O. Box 4260
5004 JG TILBURG
td. +.11 13.12.1800
REGAM b.v.
c/o P.O. Box 5
94I87.C \VIJSTER
tel. +31593639.19
landfill gas extraction:
N.V. RAZOB
P.O. Box 252
5670 AG NUENEN
tel.+3140S358S9
landfill gas utilisation:
Carbiogas b.v.
P.O. Box 243-
5670'AF. NUENEN'
tel. +31 40839683
COCAS N.V.
P.O. Box 71
7600 ALMELO
tel. +315490.16666
landfill gas extraction:
Streekge\vcst \Vestclijk
Noord-Brabant
P.O. Box 90
4700 AB ROOSENDAAL
tel. +31 1640.18400
landfill gas utilisation:
N.V. PNEM \Vesi
P.O. Box 151.1
4700 BM ROOSENDAAI.
tel. +31 165081700
N.V. FRIGEM Z.O.
P.O. Box 100
8400 AC GOKKEDIJK
tel +M 51 V> 7*175
NOVEM h.v.
P.O. Box 8242
350.1 RE UTRECHT
tcl. +31.1036.1444
Pctrogjs Gas Systems b.v.
Doeshurjiweg?
280.1 PI. GOUDA
id. +.11 182065395
Grontmij. N.V.
P.O. Bo.x 20.1
373(1 AE DEBII.T
tel. +3130207911
Eltacon b.v.
P.O. Box 276
2700 AC ZOETI-KMEF.R
icl. +31 79 4 197 II
Leybold-Hereaus
Hanau
Germany
De VriesStortgasb.v.
P.O. Bo.x 90
8500 AB JOURF
tel. +31513884444
CIRMACb.v.
Bleekerssingel 22
2806 AA GOUDA
tel. +31 1820 1 1344
Pctrogas GasSvsierm b.\
Doesburgweg 7
2803 PL GOUDA
tel. +31 182065395
De V'nesStortg.T; b.\ .
P.O. Bo.x 90
8500 AB (OURE
tel. +31 51. 18 84444
Jenbach Sandfirden
Energv Systems b.\ .
P.O. Box'l466
3800 Bl. A.MERSFOO In-
tel. +3133652752
Petrogas Cias Systems b.\ .
Doesburg\veg 7
280.1 PL GOUDA
td. +31 182065395
Association of energy distribution
companies in tbe Netherlands
1-ncrgieNed
P.O. Box 9042
Gronnnij. N.V.
P.O Box 203
3730 AE DEBII.T
tel. +31 30 20791 1
GASTEC N.V.
P.O. Box 137
7300 AC APELDOORN
tcl. +31 55494949
,
Innogas b.v.
P.O. Box 404
4200 A K GORINCHEV1
tel. +31 18.10.15466
GASTEC N.V.
P.O. Box 137
7300 AC APELDOORN
tel. +31 55494949
Institut fur Verfahrcn.stcchnik
Tcchniscbe Hochschule Aacht-n
Gc-rmanv
GASTEC N.V.
P.O. llox 137
7300 AC APELDOORN
tcl. +3155494949
\Viiste Processing Association
WAV
P.O. Box 19300
3.501 DH UTRECHT
lei. +.11 .10.1I6N05
6800(iD ARNHI-M
tcl. +3185569444
tcl.+31.10311144
E-10
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Notes on Two Dutch Landfill Gas Workshops
This section summarizes notes on two workshops held in the Netherlands on May 7, 1992, and November
18, 1992. The workshops were organized by Adviescentrum Stortgas (Landfill Gas Advisory Center),
Utrecht, the Netherlands. The Advisory Center is an initiative of the United Utility Companies, the
Organization of Waste Management Companies, and the Netherlands Organization for Energy and the
Environment (NOVEM). NOVEM is the main scientific government research institution in the country. The
Center provides information, consulting and project management services to encourage the utilization of
landfill gas in the Netherlands. Participants at the workshops were owners/operators of landfill gas utilization
installations. There were 41 participants at the first event and 58 at the second event. At each workshop
distinct topics were addressed. Each topic was introduced by an expert who would pose certain axioms to
generate a discussion.
Conclusive statements from the workshops that may be of interest for U.S. readers are listed below.
Managerial Issues
• The objective of the landfill owner (and government) should be to consider and manage all
pollutants from the landfill integrally.
• Gas collection is part of sound landfill management. Cost for a collection system should be
seen as part of total refuse management.
• Often, regulations pertaining to refuse management are not written to encourage gas use.
• It may be beneficial to combine management of collection and utilization activities and place
responsibility on the utilization team. The user is dependent on gas of a sufficient and
consistent quality. Also, the user must have the ability to react quickly in case of
undesirable variations. Before all responsibility can be concentrated at the user, all parties,
including energy buyer and landfill management, need to communicate effectively.
• Air intrusion, either through the cover or through leaking seals can result in output reduction
or shut down. Also, gas flow may be influenced by damage to pipelines and wells as a
result of settlement. The responsibility for addressing these issues must be addressed in
advance, by developing a proper agreement between the parties concerned. Although
overall responsibility may be with the user, the landfill owner will cooperate better if the
owner has some kind of financial interest.
• If O&M is contracted out, education of personnel is not a direct concern for the utilization
equipment or landfill owners. One participant stressed the importance of the availability of
proper manuals, operating procedures, and trouble-shooting guides. If these reference
materials are available, personnel with a lower level education may be able to perform
satisfactorily.
Technical Issues
• One of the disadvantages of pipeline quality clean-up, compared to electricity generation is
that the system cannot be modular.
• Pumping of gas wells to enhance landfill gas production is not always effective. Field tests
have shown that the effect of pumping can be quite local. This would depend on the density
of the refuse.
E-11
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• Dutch landfill gas experts believe that leachate recirculation is not necessary and want to
remove gas as well as water, some believe that the water would obstruct landfill gas
production although no proof of this effect has been found (not including completely
"drowned" wells). It is believed that refuse contains enough initial moisture to initiate and
maintain landfill gas production.
• One landfill owner mentioned that they immediately apply final cover in filled areas. The cost
of potential cover repair is less than the cost of additional leachate management.
• Sump pumps to remove the water should be equipped with an automatic minimum control
level.
• There are three basic schemes for cogeneration: 1) use heat for refuse treatment, 2)
(re)locate industry on landfill site, 3) move electricity generation scheme to location where
heat can be used. In the Netherlands, one landfill gas cogen-project generates clean air of
120°C (250°F) which is being used for drying chemicals. At another (planned) site, heat will
be used at the landfill to dry sludge from biological leachate treatment and for composting.
(Cogenenration is expected to have 76% efficiency.) In a third scheme, dried and
compressed landfill gas is shipped 3 km to green-houses. The cogen installations will be
built next to the green-houses. In the summer, when no heat is necessary, the generators
will be cooled by air.
Commercial Use of Carbon Dioxide: By-product of Landfill Gas Purification
Landfill gas may be upgraded to pipeline quality (natural) gas. Landfill gas is separated into a CH4 rich
stream and a CO2 rich stream. The CH4 rich stream is further purified and sold, the CO2 rich stream is
usually considered to be of little value. At best, the CO2 is used for on-site regeneration of carbon
adsorbers, or for leachate neutralization (as carbonic acid).
In a project funded by NOVEM, Innogas B.V., the Netherlands, researched possibilities to upgrade the CO2
rich stream to liquid or solid ("dry ice") CO2 for commercial purposes at the Wijster 2 landfill in the
Netherlands. This site produces landfill gas at a rate of approximately 1,200 rrvVhr (700 cfm) and employs
pressure swing adsorption for purification. The raw CO2 rich stream coming from the pressure swing
adsorption contains 90 to 96% CO2. The study concludes that upgrading of CO2 from landfill gas purification
projects to marketable quality is technically, as well as economically, feasible.
It was calculated that costs for producing liquified landfill CO2 are approximately $ 0.04 per kg and for dry
ice $ 0.18 per kg, excluding storage of the gas. These costs are below Dutch market prices for CO2.
(Commercially available liquified CO2 of aforementioned purity costs between $ 0.08 and $ 0.22 per kg and
dry ice may cost as much as $ 1.00 per kg.) One of the findings of the project was that a market for the
CO2 should have a regional character, due to the cost of transportation. It was therefore, recommended to
integrate the landfill CO2 into the distribution network of an existing industrial gas vendor. Transportation
costs for liquid CO2 run around $0.02 per kg (40,000 Ibs tanker truck, 100 miles, $60.00 charge for
unloading, CO2 at 300 psi).
Possible markets for the CO2 mentioned in the study are:
• greenhouses (plant feed),
• wastewater treatment plants (pH correction),
• the plastics industry including plastics recycling (blow gas in styrofoam or foil production and
coolant),
• the transportation sector (coolant),
E-12
-------
• fire extinguishers, and
• welding purposes.
Although technically possible, purification to foodgrade is not being considered.
At present, a follow up study is being conducted by Innogas which involves the construction of an installation
for landfill CO2 purification that will comply with the following criteria:
CO, > 99.7 vol.%
Yo
H2O < 0.015 mass.%
CO < 10.0 vol. ppm
S < 1. mass, ppm
Oil < 5. mass, ppm
NOX < 30. vol. ppm
CH4 < 0.5 vol. ppm
Taste and smell: Not detectable when gas is dissolved in water.
Information made available by:
Ingenieursburo Innogas b.v. (Mr. Frans R. van Gaalen), P.O. Box404, 4200 AK Gorlnchem, The Netherlands
(Phone 31.1830.35466).
Landfill Gas Advisory Center (Mr. Martin Scheepers), P.O. Box 19300, 3501 DH Utrecht, The Netherlands
(Phone 31.55.494581).
EXPERIENCE IN THE UNITED KINGDOM
Since the early 1980s, when landfill gas was first used in the UK, there has been an expanding industry
dedicated to the control and use of landfill gas. Support from the UK Government assisted in furthering the
understanding of landfill gas generation and the technology of its collection and use, helping energy recovery
from landfill gas to become one of the most important renewable energy resources in the UK.
The growth of the industry is presented in Figure E-1, which shows the steady progress made through the 1980s
in terms of numbers of projects. The two main uses for landfill gas in the UK are as fuel for 1C engines acting
as prime movers for power generation, and as a source of process heat in industries such as brick
manufacturing. The acceleration of this industry growth so far in the '90s is of note, as is the shift to power
generation. The use of landfill gas in the UK represents a primary energy savings that is equivalent to about
300,000 tonnes of coal per year (Maunder, 1993).
In 1993, the Energy Technical Support Unit of the UK Department of Trade and Industry published a
comprehensive document entitled: "Guidelines for the Safe Control and Utilisation of Landfill Gas." (Cooper
et al., 1993) The guideline series comprises the following parts:
• Part 1 Introduction
• Part 2 Control and Instrumentation
• Part 3 Environmental Impacts and Law
• Part 4A A brief Guide to Utilising Landfill Gas
Part 4B Utilising Landfill Gas
E-13
-------
• Parts Gas Wells
• Part 6 Gas Handling Equipment and Associated Pipework
• Projected for 1993
• Combined Heat Power
EJ Power Generation
D Boilers
• Kilns/Furnaces
81 82 83 84 85 86 87 88 89 90 91
92
93
Figure E-1. Energy from landfill gas in the United Kingdom.
Although these guidelines were written from a safety aspect, they contain useful information on topics relevant
to this report. The following sections from this document are included in this Appendix:
• Part 1, Introduction, Section 3, "Quality Assurance and Risk Management." (Page E-16)
• Part 4B, "Utilising Landfill Gas." Section 4, "Gas Utilization Technology" and Annex D, with
Tables of Operating Details of Some U.K. Landfill Gas Utilization Schemes. (Page E-36)
Reference:
Maunder D.H. 1993. Nontechnical Barriers to Using Landfill Gas in the UK and a Discussion of Some
Solutions. SWAN A 16th Annual Landfill Gas Symposium, March 1993, Louisville, KY.
Cooper, G., Gregory, R., Manley, B.J.W., and Way/or, E. 1993. Guidelines for the Safe Control and Utilisation
of Landfill,Gas. ETSU B 1296-P1. DoE Report CWM067A/92.
E-14
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Quality Assurance and Risk Management
Excerpt from "Guidelines for the Safe Control and Utilisation of Landfill Gas."
Cooper, G., Gregory, R., Manley, B.J.W., and Naylor, E. 1993.
ETSU B 1296-P1. DoE Report CWM067A/92.
Reproduced with permission from the Energy Technical Support Unit (ETSU), Department of Trade and
Industry, U.K.
Address of ETSU:
Harwell, Didcot
Oxfordshire OX11 QRA
United Kingdom
Telephone: (44) 0235 43
Facsimile: (44) 0235 43
E-15
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QUALITY ASSURANCE AND RISK MANAGEMENT
3.1 INTRODUCTION
This Section has been included to ensure that by the adoption of Quality Assurance
(QA) and Risk Management principles, LFG will be controlled, and if appropriate,
utilised, in a safe and effective manner.
These principles examine both the organisation required for the management of
LFG as well as its response to given events. Quality Assurance seeks to 'get it
right' first time and every time by the creation of formal procedures to deal with
the management of the entity and bring about the necessary responses on a day by
day basis. Risk Management looks at potentially unacceptable events and identifies
ways in which they may be prevented, mitigated or insured against.
By coupling QA and Risk Management, it is intended that the organisation and its
functions should be scrutinised and formalised to ensure safety and reliability in
system operations. Other safety systems eg. Health & Safety, Environmental, may
also be established and coupled in a similar way as part of an overall management
control structure.
QA as a documented management system, was first introduced in the 1960's by the
US Military when it was found that a major defence project was being prejudiced
by the poor performance of the Contractor. Materials and services were not
meeting the specifications and were being delivered late, resulting in serious delays
and extra costs.
As a result of this experience, the US Military introduced a Quality System
Standard which set out eighteen significant elements of Good Management. These
eighteen elements have stood the test of time and form the basis of the International
Quality System Standards such as BS 5750(1987) - Quality Systems, [ISO 9001,2,3
- EN 29000].
QA is not an assurance, per se, that the end product or service is of a particular
standard. It is an assurance that the correct procedures have been followed in the
act of producing a product or providing a service, and therefore by implication,
achieving the planned result.
During the last decade there has been a growing appreciation of the direct benefits
derived by Organisations operating QA or Quality Management Systems and to an
increasing extent, the way in which Quality Management is regarded as an
important element in the selection of contractors by Public Sector Organisations
and Regulatory Bodies.
QA is not Quality Control or Inspection, which is the checking activity which takes
place at the point of delivery of the service. QA is about planning, designing and
organising resources to achieve a consistent and repeatable result, and the 'design
aspect in its wider meaning, features significantly in the QA ethos.
E-16
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With a simple inspection procedure, when the product or service is found to be at
fault at the point of supply, then there are delays in the provision of the product or
service and additional costs are incurred in correcting the faults.
In the case of operation of hazardous installations or the provision of emergency
services, this late discovery of faults in the equipment, system or service, may have
a serious effect upon safety.
QA is pro-active, intended to "prevent failures. It is concerned with the planning
and preparation activities to ensure that the product or service is acceptable at the
point of delivery, and that it is of the required quality and reliability.
Quality Control is reactive, concerned, with the discovery of failure at the point of
delivery.
3.2 QUALITY ASSURANCE AS APPLIED TO LANDFILL GAS
In applying a Quality System to the control and utilisation of LFG it is first
necessary to analyse the full range of activities involved and the responsibilities
which have to be acquitted. These may include:
• definition of concept and design;
• planning;
• construction;
• operation;
• restoration; and
• monitoring and regulation.
Each of these may have, in varying emphasis, a number of organisational aspects
under an assurance system. Furthermore, later phases may influence earlier phases
as a result of feedback, changed circumstances or legislative requirements.
This multifaceted role of QA is best represented by the matrix shown in
Table 3.2a which identifies the principal stages in implementing a LFG
management scheme.
For each marked grid position, procedures may need to be developed to achieve
the required outcome, and as an overlay, there will be a.management system for
QA itself to ensure that it reflects reality and best current practice, and achieves
the desired result, measurable by audit.
E-17
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Table 3.2a QA Applied to LFG Management
CD
OPERATION
Management Responsibility
Quality System
Contract Review
Design Control
Document Control
Purchasing
Purchaser Supplied Products
Production Identification
Process Control
Inspection A Testing
Inspection, Measuring and
Test Equip.
Inspection & Test Status
Control of Non-Conform
Products
Corrective Action
Handling, Storage, Packing A
Delivery
Quality Records
Internal Quality Audiu
Training
Servicing
Statistical Techniques j
Feasibilit Concept/Dcs Design Construction
y- ign Devetopmc (Landfill)
Study Criteria nt Phase 4a
Phase 1 Phase 2 Phase 3
XX XX
XX XX
xxx
XX XX
XX XX
xxx
X
K
X
X
X
X
XX XX
XX XX
X
XX XX
XX X X
XX XX
X
XX XX
Construction
(Facilities)
Phase 4b
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Operations
(Landfill)
Phase 5
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Operations
(Oai
Production)
Phase 5b
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Shut-Down
Phase 6
X
*
X
X
X
X
X
X
X
X
X
X
X
X
X
X
*
*
Monitoring
Phase 7
X
X
X
X
X
X
X
X
X
X
X
X
X
X
x.
-------
3.2.1 Qualify Assurance System Management
The management of a QA system depends upon the following.
• Satisfactory management structure with clearly defined responsibilities and
duties.
• Use of good engineering planning and practice.
• Competent staff in key positions.
• Accurate and reliable records.
• Techniques to accommodate variations from instructions or management system
improvements and upgrades.
• Good communications and document control.
• Checking or auditing the system.
Design and Planning
Emphasis should be given to the need for prevention of failures through design
(planning and preparation) which is the most critical of all activities.
It must be used as the basis for control and should be reviewed systematically by
competent persons throughout all the phases shown in Table 3.2a.
If the design concept is flawed then even the best construction and operational
practices are unlikely to overcome the design deficiencies.
In considering the various phases of LFG management, it is convenient to utilise
the framework of BS5750/IS09000 as a typical and well recognised UK standard.
There are others, for example Military standards such as AQAP, in which the
principles are the same, though the detail may be altered to suit particular
requirements.
In order to emphasise the importance of systematic consideration of, (and reference
to), the design criteria and the site licence, the reader is referred to Pan 1 of
BS5750/ISO 9001.
BSS750 Pan I/ISO 9001
The Standard sets out the requirements for a Quality System under 20 headings,
and these can be related to the phases of LFG management shown in Table 3.2a.
When referring to BS5750 it must be appreciated that is has been written
principally for the manufacturing industries. However, there are now several
applications of BS5750 in service industries such as Waste Management.
The principles of good management, however, are common to many industries and
the requirements of BS5750 can be interpreted for the management activities of
landfill and the control of LFG.
E-19
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The Institute of Wastes Management in association with the British Quality
Association has produced an interpretation of the Standard entitled 'Applicability of
, Quality Assurance and BS 5750 to the Disposal of Waste to Landfill', (September
1990) and this is a good first point of reference.
The issues are discussed in relation to each of the phases given in Table 3.2a in the
following sub-section.
3.2.2 Phase J - Feasibility Study
At the initial stage of a project the objective is to determine if the proposed activity
is practicable and economically sound. It is necessary to implement good design
management practices at this stage to avoid incorrect conclusions being arrived at
with the possibility of progressing to further stages on a project which is either
technically flawed or not economically viable.
Matters to be considered at this stage include the following.
• Proposed services, the proposed site and its previous use.
• Composition of the waste.
• Origin of the waste.
• Site capacity, topography, hydrogeology and geology.
• Environmental aspects of visual impact, noise, traffic, odour, water and vermin.
• Health, safety, hazard and risk analysis.
• Site and gas management facility layout.
• Gas management systems.
• Electrical systems.
• Site utilities, water, electricity etc.
• Site offices and accommodation etc. •
• Site life cycle programme.
• Economics.
• Operating philosophy, including staffing.
• Gas management facilities - normal, maintenance and emergency operation.
• Legal or contractual restraints.
3.2.3 Phase 2 - Concept and Design Criteria
Generally this phase follows the same areas of consideration as the feasibility
study, but goes into more detail in areas such as the operating philosophy, selection
of materials and equipment, design construction and operations programme and the
project budgets for the design and construction phases.
This document is the 'Specification' against which the detailed design is developed.
Deviations from the 'Design Criteria' should be subject to authorisation following
consideration by competent persons.
3.2.4 Phase 3 - Design
During this phase the technical specifications and applications for Planning
Consents and the Site Licence are produced and submitted to the Regulatory Bodies
for approval. This is covered in more detail in Pan 3 in the guidelines series.
E-20
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Specifications and construction instructions are prepared and issued for the site
construction phase. This may involve a prequalification procedure in the case of an
'arm's length' contract with a Contractor to assess the competence and ability of
the Contractor to carry out the work.
Records, including identification of the source of the information, showing the
original site layout with drawings of the existing surface and underground services
within or adjacent to the site, groundwater, location, (flow and initial analysis), etc
should be made available and should be subjected to critical examination for
completeness and accuracy before accepting the information for design.
The records should be retained on file and be available for retrieval at any time
during the life cycle of the site.
Following the preliminary evaluation of the site and its development, the
programme of site fill, nature of the waste, etc, the estimates of the quantity and
quality of LFG will be determined and the gas collection system layout diagrams
produced. These diagrams should be developed to cover the gas management
facilities, including any gas utilisation, and should include mechanical, electrical,
instrumentation, control and safety systems.
In engineering these facilities, consideration should be given to the profile of gas
generation and should consider normal, maintenance and emergency operation.
Some degree of over capacity and component duplication should be included in the
design to ensure the safe operation of the facilities under all operating regimes.
During each of these phases the Quality System requires review of the design input
information, employment of appropriately qualified and experienced staff, records
of calculations and checking by competent staff. Where computers are used in the
design, then it is essential that the software used should be verified by independent
or alternative calculations to confirm its suitability and accuracy.
At appropriate intervals during each of the design phases there should be 'design
reviews'. These reviews should be attended by representatives from other
disciplines, eg. construction, operations, engineering etc. and should consider the
development of the design against the intended use, the site licence (actual or
proposed), good practice and the legislation. Techniques such as 'brain storming',
'what if, 'fault tree analysis', 'cause and effect analysis', 'hazan' and 'hazops'
may be used. Care should be taken to consider both normal operations and
'abnormal' operations and systems should be designed to fail safe.
The commissioning, operating and decommissioning procedures should be defined
and documented during the design phase and commissioning of the facility should
not be permitted to proceed in the absence of these documents.
Written procedures should be implemented for all the design activities and the
quality system should also include written procedures covering all the activities as
indicated in Table 3.2a.
Particular attention should be given to the training of operators, permit to work
systems and the amendment protocol for both working procedures and the design
of the facilities.
E-21
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Internal audits should be carried out to ensure that the documented quality system
is being implemented and is operating effectively. These internal audits should be
planned and systematic, and should be carried out during each phase at appropriate
intervals.
Records of the internal audits and the introduction of any corrective actions should
be maintained and should be reviewed regularly to ensure that the quality system is
operating satisfactorily and also to consider any financial or technological changes
which may influence working practices and the quality of the design.
3.2.5 Phase 4A- Construction (Landfill)
This phase of the project is understandably critical with respect to the future safe
operation of the site and control of LFG, but in the majority of cases this will not
be carried out by the Site Owner but instead by a Contractor or a number of
Contractors and Subcontractors.
The operation of a Quality System will ensure that the integrity of the design'is
maintained through design amendment procedures and the quality of workmanship
verified by inspection and records which should be produced and kept for future
reference.
Good management practices, as defined by QA standards, require the Site Owner
to ensure that the Contractor(s) selected for the task have the relevant experience
and resources to undertake the Contract, and have established procedures and work
instructions which will minimise the risk of sub-standard contract completion.
The respective responsibilities of the Owner and the Contractor can be summarised
as shown in Table 3.2b.
3.2.6 Phase 4B - Construction (Facilities)
The construction of the gas management facilities is likely to be programmed over
an extended period with the operation of the landfill site progressing for some time
prior to its installation.
The gas management system should be followed by the construction and
commissioning of the gas handling, distribution and utilisation facilities which may
well be phased to suit changing gas quantities. This may involve more complex
construction procedures to maintain safety and quality of work.
The responsibilities of both parties for this phase will be broadly the same as those
given in Table 3.2b.
E-22
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Table 3.2b Responsibilities
Owner
Contractor
Compile specification with:
• clear instructions;
• standards to be achieved;
• constraints (Do's & Don'ts);
• tile licence requirements; and
• regulation requirements.
Identify lines of communication
for reporting and approval of
alterations or amendments.
List records to be maintained and
supplied at end of construction.
Assessment of contractors capability
to perform, including:
• experience;
• systems and procedures;
• references; and
• previous work standards.
Review of specification including:
• listing Kerns not fully defined;
• discussion with owner on above; and
• records of outcome/amendments.
Plan project and produce Quality Plan
including:
• description of project;
• Contractor! and Owners organisation;
• lines of communication;
• standards to be achieved; and
• procedures to be used.
Establish procedures for the Contract and
ensure staff adequately trained.
Implement procedures
Carry out systematic audits of Quality System
to ensure that it is operated effectively
Where non-conformances are identified, to :
• correct the non-conformancc; and
• examine the conditions which gave rise to the non-
conformancc and change or eliminate those conditions.
3.2.7 Phase S • Operation (Landfill)
The operational phase of the landfill site conducted by either the Owner or a
Contractor should be subject to good operational and management practices as
outlined in recognised Codes of Practice, Regulations and the Site Licence.
The implementation of a Quality Management system (such as BS 5750) will be a
major contributor to good practice. A good interpretation of this is to be found in
the Institute of Wastes Management publication 'Applicability of Quality Assurance
to Disposal of Waste to Landfill'.
In establishing the operating procedures il is important that the interfaces between
the collection and handling and the utilisation of LFG are adequately addressed.
E-23
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3.2.8 Phase SB - Operation (Gas Production)
Gas handling, distribution and utilisation (eg. generation of electricity) are all
potentially hazardous activities and it is important to establish good operating and
maintenance procedures, and to ensure that staff are fully instructed in their use.
A rigorous system of permits to work should be established for potentially
hazardous areas and be followed in detail by all staff. There are accounts of
catastrophic events arising out of failure to observe such systems.
Test equipment and instrumentation required in the operational phase should be
recalibrated on a regular basis if its output is to be relied upon for indication or
control. These instruments require careful maintenance and are probably the most
important components in the safe operation of gas management installations.
3.2.9 Phase 6A - Shutdown (Landfill)
In most cases the shut down of the landfill site operations will precede that of the
gas handling system which may have to continue operations for up to 30 years
more.
Following the completion and closure of the landfill site and placement of the
capping and restoration layers, most of the operational staff will depart and the
responsibility for subsequent site monitoring may be passed on to others.
Whosoever has this responsibility should ensure that monitoring procedures,
acceptance, warning and alarm levels are established and the reporting procedures
include regular confirmation that the site condition is safe and environmentally
acceptable. The Regulatory Authorities and their role should also be clearly
identified.
All parties should be aware of their management responsibilities and interfaces,
forms of reporting, periodic review and verification of the monitoring procedures,
and formal management reviews of the reports and trends. Records should be kept
based on measurements or observations recorded.
Procedures, responsibilities and the lines of communication should be established
and documented identifying the actions to be taken in the case of an incident.
3.2.10 Phase 6B • Shutdown (Gas Production)
As gas generation will decrease with time, the decommissioning of the gas handiinj
and utilisation facilities will probably be phased and plant, equipment and staff will
gradually be removed from the site.
As the dismantling and removal of the plant may be carried out alongside operating
plant by staff or contractors brought onto the site for that specific task (and not
necessarily familiar with working in hazardous environments), there is a need to
plan and prepare procedures for the decommissioning of the gas handling plant
from the outset.
It is important to ensure that small or post operational sites are included in the
routine of internal audits and management review, and are not overlooked. This
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can be avoided by formulating procedures to ensure that there is regular
environmental auditing, and careful review of the site reports, in addition to a QA
systems audit.
3.2.11 Phase 7 - Monitoring
A site should be monitored until such time as it has been finally verified that it
poses no threat to the environment, and this monitoring should be undertaken by
competent persons in accordance with agreed procedures.
Regular audits and reviews of the effectiveness and meaningful ness of the
monitoring programme and records should be conducted by the responsible
management and the Regulatory Authority as required.
The instrumentation used in monitoring must be suitable for the purpose for which
it is used and calibrated appropriately, and this operation must be included in the
internal audit programme of the organisation responsible for monitoring.
Whilst the above is mainly concerned with the activities of the organisations,
Owners and Operators directly responsible for the operations, the Regulatory and
Statutory Bodies should also be aware of their responsibilities and their interfaces
in the management systems.
Ideally these Regulatory Organisations should have established their own quality
systems, with written procedures to ensure that their staff are fully aware of their
responsibilities, are trained to carry our their duties, and respond correctly at all
times avoiding delays in decision making, particularly as delays may have
detrimental effects on the gas management system and safety.
3.3 TRAINING AND PREPARING STAFF
The requirements of The Environmental Protection Act of 1990 (EPA 1990) and
the management of a QA system place emphasis on competent persons in key
positions, and this implies:
• well defined task or job responsibilities;
• effective recruitment and selection of employees;
• thorough initial training and preparation;
• safety and quality awareness (Important for insurance purposes); and
• on-going vocational training.
Systems are required to identify the forms of training required to deal with the new
recruit to LFG operations, and to upgrade the incumbent employee as techniques,
systems or responsibilities change.
The employee should be trained to operate equipment and perform tasks safely with
a background of knowledge as to what the implications or effects of his actions
may be.
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Competent well-trained persons are required for the design, construction, operation
and monitoring phases of the scheme, with specific high levels of competence for
operational specialists and additional certified levels of competence for mechanical
and electrical specialists.
Training should include instruction by persons who understand the problems and
difficulties of the tasks, so that the training has relevance and credibility.
Equipment specialists may feature in this programme.
QA systems require that training should be conducted in a formal manner,
examined and upgraded as necessary, with appropriate records to show that
training has been given.
Vocational training and feedback 'workshops' held between operational and design
staff on a regular basis will aid appreciation of the others problems and concerns.
Training should include sufficient background and specific relevant aspects of
legislation and regulations applicable to the employees responsibilities.
Employees should be provided with the appropriate tools, equipment, and
instructions for them to perform their task effectively and safely. This includes
safety or personal protective equipment (PPE) as appropriate, particularly in
relation to COSHH (Control of Substances Hazardous to Health).
3.3.1 Records
QA can only work if there are adequate records and a 'paper trail' which can be
checked and audited.
In an extreme case, it is sometimes possible to identify the complete history of each
individual electronic component in an assembly, so that in the event of failure, the
cause of failure might be identified.
Whilst most QA systems will not necessarily give or warrant this degree of
information retrieval, the ability to check and prove that procedures have been
adopted and used gives confidence to any eventual result and by installing alarm
thresholds which give a signal when reached, fault events may be identified before
they get to unacceptable or tragic proportions.
Records start with individual items of information being incorporated into larger
more complex reports and forms to give a hierarchical structure to the data, with
appropriate cross referencing between related streams of information.
Landfill sites can remain biologically active over very many years, it is therefore
important not only to ensure that records are safely and securely kept but that they
are updated regularly and are available when required for inspection, use and
analysis.
Records required will cover not only structural and design matters but the
operational details relating to how the landfill site was filled, in what order and
with what materials, which can influence subsequent gas production.
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3.3.2 Techniques la Accommodate Variations
The conceptual and detail design and planning stages for a LFG management
scheme should give rise to Working Procedures and records which are produced
and monitored by the QA system.
Operational experience, or additional information may lead to the need to change
these procedures, and a formalised approach should be applied to changes such that
confusion is avoided.
Changes may come about as a result of:
• changes in legislation;
• operational feedback;
• new techniques;
• modifications to equipment; and
• accidents or system malfunctions.
It is important that the system returns information from any of the sources above to
the designer or planner in order that the most appropriate action or cognisance of
change is taken. Feedback or revision information should be channelled back
through a competent person who can assess formally any variation from procedures
felt necessary and act accordingly.
In some cases, change may come about by operatives developing alternative
procedures which may differ from the 'official' procedures. Such variations may
require either corrective action or adoption if felt appropriate as an improved
method of working.
3.3.3 Communications
The production of working procedures which form the substance of QA systems
affecting day by day operations, is in itself a communications exercise to ensure
that:
• the procedures give the correct instructions in an unambiguous form to the
correct person;
• the procedures reflect reality and are workable;
• the procedures are upgraded or amended in consultation with those affected;
• there are not two or more conflicting instructions for the same event; and
• there are no unnecessary overlaps and no gaps in instructions.
Good communications are fundamental to good management, and to QA which in
this case can act as a screening and distribution exercise of the relevant
information.
LFG gas control and utilisation is a relatively specialist field which could benefit
from wider co-operation than simply in-house. Inter-organisational co-operation
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(or even international) is recommended particularly in respect of incidents that have
n;it liffi nr nronertv at risk
put life or property at risk
3.3.4 Auditing
For a QA system to work, and be seen to work, it should set out to manage its
own affairs by checking that the systems and procedures in place are working
satisfactorily. This can be achieved by audit.
The ability to audit procedures and the QA system generally is a fundamental
aspect of QA systems such as BS5750, which make them powerful in the
formalisation of management practices, since without audit the QA procedures
might never progress to implementation.
Auditing by properly trained examiners performing a Quality Audit on the'
document system being used, should aim to establish in a formal manner whether
procedures are in place, how well they are working, and whether changes are
necessary:
'Properly trained' in this context not only refers to competence in the QA system
and knowledge of its workings, but of the subject area being audited within the
system. For LFG and other specialist aspects of landfill or waste management this
will realistically be a QA specialist working alongside a landfill specialist for
aspects of detail.
An analogy to the QA Audit would be a management team reviewing its progress
every 6 months in detail, looking at customer complaints, non- compliance with
agreed standards of performance or product, changes in legislation, and readjusting
its priorities or methods accordingly.
QA does not take away from management the right to manage. Indeed it is a
powerful management tool which may reveal aspects which, if ignored, could
produce an (otherwise) unexpected result. Management may well think of the
consequences if appropriate changes are not adopted and equally what would
happen if changes are not fed back to personnel responsible for design and
planning. QA helps to do this formally if not automatically.
3.4 RISK AND RISK MANAGEMENT
In parallel with a QA approach to the design and planning of a LFG control or
utilisation system, there should also be a formal risk evaluation and assessment
exercise.
Risk management may be defined as a 'programmed plan of action aimed at risk
identification, risk evaluation and risk control (the elimination of avoidable loss and
the reduction and containment of other losses)'.
Some of the risks identified may be more appropriately considered as relating to
the landfill rather than LFG, but any overlap experienced as a result is considered
to be better than an omission.
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This is particularly true with much recent and developing environmental legislation
having an emphasis on the management of risk in accordance with the 'polluter
pays' principle. This puts the responsibility for preventing pollution and improving
the environment on industry, and for civil damages, on the polluter rather than
transferring the risk to the insurer in the first instance.
The usual approach employed within the insurance industry is as follows.
• Identify Risk.
• Evaluate Risk.
• Control Risk:
• financially; and
• physically.
The approach is stepwise, starting with risk identification, through evaluation to
risk control. The physical control of the risk should generally be undertaken by
the Owner, Operator, manufacturer etc and should utilise processes such as risk
avoidance, through, for example, selection of safe methods of manufacture or
hazard-free products. It also involves risk minimisation - for example the use of
carefully worded instructions for users of products, or guarding of machines at
installations and facilities.
The financial control of risk involves both risk retention or assumption and
transfer. In the case of risk retention the 'creator' or 'owner' of the risk elects to
retain the risk and meet any costs arising from his own funds. The process of risk
transfer is fundamental to insurance. It involves the transfer of risks from the
insured party to the insurer and is accomplished by payment of a premium. This
serves to illustrate the importance of risk identification and risk management to the
insured party in addition to the insurer.
3.4.1 Risk Identification
This initial process should be conducted by those within the organisation likely to
be involved with the LFG scheme, and can take the form of a 'brainstorming'
session at which the various interests are represented. Its purpose should be to
identify the risks by asking questions such as:
• what can go wrong?; and
• what will happen when it. goes wrong?
For a landfill producing gas this could give rise to a list such as that given in Table
3.4a below. The list is only illustrative, and the process may be summarised by
indicating risks which give rise to:
• injury to individuals;
• damage or loss of property;
• impacts on the environment; and
• consequential losses.
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Table 3.4a Examples of Potential Risks
Action
Potential Effect
Potential Risk
Landfill Operations
Landfill Gas Management
Exploitation of gas
Site lining failure, leachale
migration.
Incorrect wastes types
Litter.
Uncovered waste encouraging
birds.
Hazardous conditions on cite.
Gas 'escape' or migration
Process equipment failure
General
Flare
Settlement of landfill (gross and
differential)
Surface water &
Groundwatcr
Contamination
As above. Reaction
Cattle choking.
Aircraft bird strike.
Injury to workers,
visitors, trespassers etc.
Fire, explosion,
asphyxiation.
Plant or crop damage.
'Blighting' of land.
Gas migration or leakage
Failure to supply
customers
Consequential loss
Navigational distraction
hazard
Building structural
damage. Damage to
foundations. Damage to
gas collection equipment.
3.4.2 Risk Evaluation
The task of risk identification may suit the 'brainstorming' approach because at thai
stage no priority or likelihood evaluation is enacted, the task is simply to identify
not quantify the risks.
In order for risk to be managed, there is a need to evaluate:
• the likelihood of occurrence;
• the probable cost of occurrence (in physical and financial terms); and
• ways in which the risk could be mitigated.
The subject of risk evaluation is quite scientifically based and it is possible to
calculate the outcome and probability of most risks. In so doing, various types of
risk will be identified and may be categorised as given in Table 3.4b.
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Table 3.4b Categorisation of Risks
3.4.3
Event Probability
Lav
High
Effect when it
happens
Significant
Low
Significant
Low
Cost to overcome or
mitigate
Low
High
Low
High
Low
High
Low
High
• Possible Action
Resolve
Consider
Resolve
Ignore
Resolve
Consider
Consider
Ignore
* Shown for example purposes only.
The mathematical assessment can go further and give an indication of best
investment of time and money towards reducing the risks to an acceptable or
reasonable level, though what is 'acceptable* or 'reasonable' may be determined by
factors outside the scope of pure risk assessment or costing such as:
• legal requirements;
• Company or organisation policy or ethos; and
• public perception.
In the case of LFG, the subject is not only specialised but also has little hard
evidence with which to check theoretical predictions taken from the extrapolation
of similar risks in other industries. This absence of 'hard' information not only
makes risk assessment difficult, it makes the assessment of insurance premiums for
indemnity of these risks equally difficult for the insurance industry to calculate.
Premiums may therefore vary widely between insurance companies.
Before dealing with insurance, it is necessary to consider a further step in risk
management, Risk Control and how it is achieved.
Risk Control
Having identified the risks, the following issues should be addressed:
• the likelihood of occurrence;
• the effects of an occurrence; and
• the cost of mitigating, reducing or eliminating the risk or its effects,
The outcome should enable management to make decisions as to how to deal with
the risks.
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In some cases, for example, where there is a low probability of occurrence and the
effects of an occurrence would be minor, it may be acceptable to take the risk and
possibly insure against the event.
Most risks fall in the middle ground where it is possible to reduce the risk by:
• design;
• physical protection;
• supervision; and
• alternative methods.
These aspects may be likened to the 'design' process in QA.
It becomes a management decision as to bow many resources are put towards
reducing these risks, and the manner in which they are most appropriately dealt
with.
The preferable route is physically to produce conditions where the risk is unlikely
to occur and where if it does, the effects are mitigated to a satisfactory level.
When this is not possible, or it is judged to be too expensive for such a low risk
etc, then an alternative solution may be to provide for the event in a financial
manner. This could take the form of a financial fund which can be made available
when the event occurs.
Some events are unforeseen, erratic, Acts of God, or are difficult to predict, design
out or to avoid.
Statistics may give an indication, based on historical data and trends, of when or
how often the risk will materialise and the insurance industry is able to recognise
the probability of an event when formulating premiums for items such as fire or
accident.
The risk may be insured for 'unforeseen* cases where:
• there is a residual risk despite best efforts to avoid it;
• where there is a legal requirement; or
• where the cost of avoiding the risk is very high.
3.4.4 Insurance
Insurance considers the extent to which risk can be retained, self-funded, or
transferred for premium to an insurer.
Traditional types of insurance include the following.
• Employers' liability - injury or accident involving employees.
• Public liability - concerning accidents to third panics.
• Product liability - concerning third parties injured through use of
a product sold or supplied (eg LFG).
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• Financial or - concerning the commercial 'knock-on'
Consequential Loss effects of an event.
• Professional indemnity - breach of a professional's duty of care.
• Pollution - both sudden and accidental (generally covered
in the Public Liability policy) or gradual
pollution (difficult to obtain in the UK).
In addition, there are novel and unconventional forms of insurance facility which
may be considered.
• Industry fund or insurance pool.
• Captive insurance company.
• Environmental Impairment liability insurance (which requires a pre-insurance
site survey).
In assessing insurance premiums, and the risks which any particular insurance
company is prepared to insure, cognisance should be taken of the operator's
commitment to:
• efforts to reduce or mitigate risks;
• a comprehensive safety policy;
• a comprehensive environmental policy;
• BATNEEC (best available technology not entailing excessive cost) or BPEO
(best practical environmental option) approaches; and
• QA to a recognised standard.
Depending upon the commitment and its manifestation in reality, premiums may be
lower than for an equivalent operation which ignores risks or does little about
them. Such an organisation may well have difficulty in getting insurance in
extreme cases.
Some aspects of insurance are already a legal requirement for anyone employing
workers, running a company or operating vehicles, for example, and there has
been discussion that there should be insurance or financial guarantees to cover
potential damage to the environment.
It is too early to say whether EC directives will require compulsory insurance,
because the legislation is currently in a state of flux, but if it were the case then it
would effectively make insurers the licensors of landfill operations. However, if
insurance were not to be made compulsory, it would enable agreements to be
negotiated between insurers and operators, and allow banks to participate in the
provision of finance. However, another legislative trend is towards strict liability
for injury or damage (Directive for Civil Liability for Waste Damage) which could
involve further scope for insurance.
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Fl§ltre hi-2 Simplified Protest Cr Instrumentation Diagram for Typical Landfill Gat Abstraction and Utilisation Systc
o
m
-m-
-DKH
-W<}
pfniwrr
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Gas Utilization Technology
Exerpt from "Guidelines for the Safe Control and Utilisation of Landfill Gas."
Cooper, G., Gregory, R., Manley, B.J.W., and Naylor, E. 1993.
ETSU B 1296-P1. DoE Report CWM067A/92.
Reproduced with permission from the Energy Technical Support Unit (ETSU), Department of Trade and
Industry, U.K.
Address of ETSU:
Harwell, Didcot
Oxfordshire OX11 QRA
United Kingdom
Telephone: (44) 0235 43
Facsimile: (44) 0235 43
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GAS UTILISATION TECHNOLOGY
4.1 INTRODUCTION
Many schemes for the utilisation of LFG are technically feasible: but other factors,
such as economics, environmental and planning constraints currently limit the use
of a significant proportion.
For schemes in operation in the UK, US and Western Europe, energy recovered
from LFG has been used to drive electricity generation equipment, or may be used
directly in the following applications:
• boiler firing;
• brick burning in kilns;
• cemenf manufacture;
• stone drying;
• district heating;
• greenhouse heating;
• augmenting national gas supply (US); and
• vehicle fuel.
The methane content of the recovered gas has a strong bearing on the potential gas
end use and its economics. Table 4.la shows the minimum methane quality of
LFG for various applications.
The quality of gas required for electricity generation purposes depends upon the
type of engine used. Reciprocating engines ideally require more than 28%
methane, whilst gas turbines will run at greater than 35% methane. Tables D1-D2
in the Annex list details of some of the current utilisation schemes which produce
electricity, and show the gas yields and electricity production achievable with
current technology.
Use of gas as a boiler fuel or kiln fuel requires a minimum methane concentration
of about 35%, but this is dependent upon design of the boiler or kiln burners.
In all cases, the gas quality must be maintained above the upper explosive limit
(approximately 15% methane) for the collection and utilisation system to operate
safely. Dilution of any LFG sample, with carbon dioxide concentration of 78% or
less, by air will result in a flammable mixture being formed when dilution leads to
7-15% methane. If, however, the carbon dioxide content exceeds 78%, then no
methane - carbon dioxide - air mixture is flammable.
This is an important concept to understand because even for the safe flaring of gas,
the methane concentration must exceed -20%. For the safe flaring of LFG, a
concentration of 8% oxygen or less within the LFG (prior to addition of
combustion air) is required. Typically, oxygen concentrations in the gas from a
control scheme pumped to a flare stack will range from 2-4% oxygen, and levels
above 6% tend to indicate overpumping. Flares will not function at low methane
concentrations. Whilst this is equipment-dependent, flaring is not practicable
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below 17% methane, and equipment manufacturers will typically specify minimum
methane concentrations of between 20-25% as an operational limit for flaring.
Table 4.la Gas Utilisation End Use
Potential Gas Eod Use Minimum Methane Concentration
Pipeline methane 95% (not applicable in UK)
Reciprocating engine fuel 28%
Rotary kiln fuel 35%
Gas turbine fuel 35%-40%
Boiler fuel 35%-4O5t
Control of gas-related emissions 20% (Approx. - must be flarable)
Control of migration No lower limit if simply vented
Notes:
1. All values arc approximate and will be situation and site-specific.
2. Depends strongly on depth of cover, and extraction approach as well as end use.
There are no limits to landfill methane quality if the gas is simply vented, save to
say that there is scope for flammable concentrations of LFG to
build-up in passive venting boreholes on older landfill sites as the methane
generation rate decreases.
4.2 DIRECT USES OF GAS
To be successful, a project for using LFG as a fuel must be both technically as
well as economically sound. Each scheme is different and requires individual
attention to detail. It is, however, possible to express a general view on relative
risk and likely viability of different producer-user schemes.
By far the simplest and lowest risk option is the direct use of gas replacing coal,
oil, LPG or natural gas using modified gas burners. A number of such schemes
have been successfully demonstrated and risk to the user is low, in terms of gas
quality, use and continuity of supply. Payback for the user may be less than one
year but depends heavily upon the price negotiated with the LFG consumer. A
typical value would be 10-20% less than the price paid for the fuel replaced (e.g.
gas, oil, LPG or coal). The discount the supplier can offer will be linked to
recovery, transmission and pipeline cost which will be influenced by:
• the distance and terrain or obstacles over which the gas has to be piped;,
• the quantity of gas a user can take and variations permitted; and
• the quality of gas acceptable.
An idea! situation would be a user who could take all of the gas generated and who
is located adjacent to a landfill site: a situation often found at brickworks, cement
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works or other quarry related industries - hence the preponderance of such schemes
in this sector in the UK.
Any commercial proposition for direct burning should be based upon the
consumer's existing fuel prices, since the LFG would be offered as an alternative.
Involved in the equation are other factors such as:
• modifications to the consumers equipment;
• initial costs of gas supply (boosters, pipeline etc);
• operation of gas supply plant;
• any reduction of efficiency through LFG utilisation; and
• the percentage use of production from sue.
The supply of untreated LFG directly to British Gas to augment the natural gas
supply is not an acceptable option for a number of reasons;
• British Gas will not accept gas with less than 95% methane;
• the presence of higher hydrocarbons is also unacceptable; and
• the cost of scrubbing carbon dioxide from LFG, and removal of many of the
trace components is generally prohibitively expensive.
4.3 POWER GENERATION
The generation of electrical power using LFG is another popular method of
utilisation. In considering the prime mover for generating electricity using a
gaseous fuel, there are currently four options:
• reciprocating internal combustion engines.
• gas turbines.
• other technologies, including steam turbines, external combustion (Stirling)
engines and fuel cells.
With the exception of some of the other technologies, all are established and well
understood technologies, which have been used for power generation the world
over for a considerable period of time. All are capable of operation on LFG.
However, some modifications are generally necessary to allow for the calorific
value and flame speed of landfill gas.
Each of these is described briefly in the following sections.
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4.3.1 Reciprocating Engines
Reciprocating engines are currently the most common type of prime mover in use
on LFG utilisation schemes. They are relatively small in size (typically a single
spark ignition engine designed to operate on LFG will produce 250-60QkW of
electrical power), and so utilisation schemes can be considered with, for example, a
number of such engines employed at the start of a scheme. Engines may then be
phased out or moved to alternative utilisation sites, as gas production drops.
Reciprocating engines commonly used for LFG generation schemes fall into two
main categories:
• spark ignition; and
• compression ignition (diesel engines).
Dual-fuel compression ignition engines still have a small supplementary fuel oil
requirement (typically less than 15%, subject to the calorific value of the feed gas)
which acts as an ignition source whereas with suitable carburation, spark-ignition
engines will run entirely on LFG. In genera], the ignition timing must be advanced
beyond recommended settings for natural gas. With the absence of manufacturer's
operating data, the required setting will usually have to be determined experimen-
tally.
Lubricating oil condition must be monitored regularly. Operational experience has
shown that oil acidity builds up rapidly and that this, if left unchecked, will lead to
premature bearing failures. The characteristics of the lubricating oil employed are
critical and should be closely monitored.
Individual manufacturers specify different gas clean-up and supply pressure values.
Engines are available which will perform on relatively low quality LFG (25%
methane) whilst delivery pressures vary from 0.1 to 6.5 bar (gauge) of de-watered
LFG. Spark ignition engines are available up to approximately 3.QMWC output
(more ususally lMWe or less), whilst compression ignition engine sets can be as
large as 10MWe.
It is often possible to find high quality used or re-conditioned reciprocating engines
of various sizes. Some modifications may be necessary for use with LFG, but the
potentially lower capital cost of such plant can have significant benefits to pay back
and economic viability of a scheme.
Recently, engine manufacturers have noted the interest in the LFG market and have
been producing packages comprising engines in ISO - style containers complete
with generators and electrical control equipment. These systems are set up to run
on LFG from the start and require only relatively low delivery pressures, allowing
the use of electrical blowers, to supply the gas rather than costlier compressor
equipment.
When purchasing new equipment, these complete packages, together with a
guaranteed fixed-price maintenance contract (typically Ip - l.2p/kWh produced
including oil. pans and labour) can offer assured costs at the start of the project.
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4.3.2 Gas Turbines
The basic operating cycle of a gas turbine is simple and for open cycle operation
occurs in three stages:
• air is compressed in the compressor stage;
• the compressed air is fed to the combustion chamber, where fuel is added and
ignited; and
• the resultant high pressure gaseous mixture expands through a turbine, thereby
releasing its energy as useful work at the turbine shaft.
Gas turbines are available from as small as 50kW to over 200MW, but are usually
considered only for the larger LFG utilisation schemes.
Gas turbines used to date have lower emissions of carbon monoxide, unburnt
hydrocarbons and oxides of nitrogen than reciprocating engines, but have relatively
low conversion efficiencies. They can also be configured to provide a wide range
of operating parameters that improve efficiency, power output and emission clean-
up at increased capital expenditures through techniques such as combined cycle
operation (generating steam via a waste heat boiler and thence operating a steam
turbine).
Pre-treatment of LFG prior to supply to a gas turbine can include de-watering,
cooling, filtration, scrubbing and compressing to between 6 and 13 bar (gauge).
The carbon dioxide content of the gas is advantageous in a gas turbine during the
expansion in the turbine, thus eliminating the need for carbon dioxide scrubbing.
Additional characteristics of a gas turbine scheme include the following.
• Ability to run on several fuels. This allows the turbine to be run on another
fuel (e.g. light fuel oil) whilst the gas compressing equipment is being
overhauled and the output to be maintained as the LFG production decreases
with time, by augmenting the fuel input.
• Low vibration, allowing foundations to be relatively small, and rooftop
applcations possible for small CHP schemes.
Ambient air temperature affects the turbine output; at lower temperatures air has
greater density which has efficiency benefits for a given quantity of fuel.
Problems with gas turbine schemes on landfill projects are generally associated
with high operating and maintenance costs.
In short term projects, as many small LFG utilisation schemes are, such problems
may outweigh the benefits.
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4.3.3 Other Technologies
Steam Turbines
Steam turbines are by far the most common prime movers for the large scale (base
load) generation of electricity.
The basic steam cycle is known as the Rankine cycle. In this cycle water is
pumped into a boiler in which heat is supplied to convert the water into steam.
This steam is then utilised in a steam turbine to drive the alternator. The steam
exhausting from the turbine is condensed and then pumped back to the boiler to
complete the cycle.
Steam is supplied to a turbine at high pressure and temperature from a boiler and
the energy in the steam is converted into mechanical work by expansion through
the turbine.
Steam turbine characteristics can be distinguished from turbo-charged reciprocating
engines and gas turbines in that the LFG requires minimum compression for use in
the boiler of the steam turbine. In addition, the LFG is fired on the external
surfaces of the boiler tubes and the products of combustion exhaust through the
stack. Therefore, any corrosion affects the static cooled components rather than
hot moving parts. Steam turbines, however, require auxiliary equipment such as
water treatment, cooling towers, water disposal (blowdown), water make-up, water
pumps, etc. Some boilers may also require continously manned operation.
Because of these factors, only larger plants should be considered for economic
operation.
External Combustion (Stirling) Engines
Unlike reciprocating and gas turbine engines which are based on internal
combustion of the fuel, the Stirling Engine is an external combustion device, using
an inert gas as the internal working fluid. The external combustion process is
required to act at typically one end of the engine and is quite separate from the
internal working fluid and moving parts where lubrication is required. As a result,
combustion conditions can be adjusted to suit the fuel, lubricants avoid
contamination from contact with combustion products, and the heated section of the
engine is easily accessible for cleaning, repair or maintenance.
Unfortunately, development of the Stirling Engine has been spasmodic, and in
recent years has focussed on smaller units. Typically the power range may be
measured in hundreds or thousands of watts. Larger units may have outputs from
5kW to about 50kW.
For a user of LFG, the Stirling Engine gives certain advantages, but unless larger
units are developed, their use may be confined to remote applications (where there
is no electrical power but there is a source of LFG) where it could drive a
generator or pump:
• to extract gas and provide a reliable supply to a local flare;
• to provide electricity for local use; and
• to pump borehole or local leachate;
E-41
-------
Fuel Cells
The fuel cell is an emerging technology that can convert methane directly to
electricity. Currently a 4QkW unit is in operation on LFG at Industry Hills,
California. The-Industry Hills unit operates with a gas pretreatment train
consisting of a carbon dioxide membrane separation system and an activated carbon
bed.
Fuel cells are still in the transition from research and development into production.
Few units have been produced to date and as such purchase costs are very high.
This coupled with the level of gas processing required, render such schemes
beyond practical and financial reality for the current UK market.
4.4 COMBINED HEAT AND POWER (CUP) SCHEMES
All forms of electrical power generation by mechanical means rely on heat being
released of which only a proportion is used effectively. Losses are in the main
through exhaust gases and cooling water and these can account for up to 75% of
the total energy input value. Means are available to utilise a large proportion of
this otherwise wasted heat for other processes, thereby increasing the overall
thermal efficiency of the scheme and generally enhancing the economic viability.
Such schemes are generally known as Combined Heat and Power (CHP) cycles.
There are several possible uses of the waste heat and these can often be tailored to
suit the local requirements.
Common CHP schemes utilise the heat as follows:
• high pressure steam for either process uses, or further electricity generation in
steam turbine plant;
• low or medium pressure hot water for pre-heating boiler feedwater, district or
building heating;
• low pressure steam for absorption chillers to provide cooling water for air
conditioning of buildings etc; and
• high pressure steam for injection into the turbine stage of a gas turbine (which
results in a significant increase in output of up to 50%.
Whilst CHP schemes using reciprocating engines are possible the lower grade of
heat available imposes certain restrictions to the number of permissible options.
However, a number of engine manufacturers provide this option as pan of their
LFG gas engine 'package'.
Although advances have been made in more efficient design of smaller sized steam
turbines, the capital cost and size of the auxiliary plant are high for such a prime
mover. However, use of small turbines in a CHP scheme could still be considered
as a potentially attractive proposition.
-------
Annex D
Tables of Operating Details of
Some UK Landfill Gas
Utilisation Schemes
TABLE Dl Utilisation Information for
Electricity Generation Schemes
- Site Plant Details
E-44
TABLE D2 Utilisation Information for E-46
Electricity Generation Schemes
- Site and Economic Viability
TABLE D3 Utilisation Information for Direct E-48
Use Schemes
- Site and Plant Details
TABLE D4 Utilisation Information for Direct
Use Schemes
- Site and Economic Viability
E-49
E-43
-------
Table Dl - Utilisation Information for Electricity Generation Schemes - Site and Plant Details
Landfill Site
Allsnpp* Hill
m
Applcy Bridge
'L1 Field. Slcwnrtliy
Operator
Tjpe of System
End Use
Observed Problems Serrice Period
Reference
Tarmac
Econo waste
Wimpey Waste
Management
Mainsprint Joint
Venture
Shanks and
McEwan
(Southern) Ltd
Two re-buill Allen dual-fuel
reciprocating engines
producing lOOOkW. Directly
coupled to air cooled Brush
generators.
Two Brons Man VI8 spark
ignition naturally aspirated
engines each I.05MW
415/11000V. Two to follow
(1991). Two planned.
Reciprocating spark ignition.
4 Dorman turbo charged 12
cylinder engines. 275kW
output al lOOOrpm on landfill
gas.
Gas compression:
Single constant displacement
vane type unit supplying
680m'/hr
Electricity
Two-thirds exported to
Midlands Electricity Board.
One-third internally for
power to Tarmac during
operations.
2.0MW of electricity and
0.7MW of hot water
recovered from one engine
cooling system. Export to
Norwcb, internal
electricity, and water to
fish farm.
Electricity.
73% of electricity to local
brick works (London Brick
Company)
14% to Eastern Electricity
Board
13% for internal
consumption
Good (1990)
Grid system
variations, gas
delivery techniques,
and minor electrical
faults on auxilliary
equipment
Mninly in areas of
the plant not
associated with
burning of Landfill
gas. Some wear and
deposits in some
areas
Minor 1250 hours.
Major 8750 hours,
12,000hrs, 20,000hrs
5000 hours
10000 hours
16000 hours
22000 hours
28000 hours
34000 hours
Thomns (1991)
Ewbank Prcece Ltd
(1990)
Homsby (1990)
MOSJ (1991)
-------
Table Dl - Utilisation Information for Electricity Generation Schemes - Site and Plant Details (contd)
m
i.
en
Undfill Site
Mcriden
(P.ickinglon)
Ollcrspool
Slonc Pit (1)
Operator
Packinglon
Environmental
Energy
Resources Lid
(PEER)
Merseys idc
Development
Corporation
Blue Circle
Type of System
Cenlrax Gas Turbine
1 x 3.65 MW
British Generator
- BARSD- IlkV 3-phnsc
50 Hz at ISOOrpm Hr
Two Caterpillar G399 spark
ignited gas engines with
generators producing
lOOOkW configuration oC
VI6. Run directly on
landfill gas.
Two Caterpillar spark
ignition (ex-diesel) engines.
Configuration of VI6 and
producing 720kW
End Use Observed problems Strrice Period
Electricity generation.
Exports to East Midlands
Electricity Board
Electricity exported to
Local Electricity Board.
Electricity exported to At npprox 3000 hours Overhaul every
Local Electricity Board severe wear had 10,000 hours
occurred on the
valves of one of the
engines.
Reference
Homsby (1990)
Malan (1988)
Robinson (1990)
Slonc Pil (2)
Wapscy's Wood
Britannia Refined
Metals Ltd
Green Land
Spark-ignition engines
650kW output
l.2MWdual fuel engine
fitted with 3.3kV alternators.
Dual fuel6!585bhpor
l256.5kW600rpm
Electricity generation for
internal use.
Electricity generation.
Exports to Spulhcm
Electricity
No evidence of
corrosion or faults.
Gas scrubbing
systems used
Robinson (1990)
Limbrick (1990)
-------
Table D2 - Utilisation Information for Electricity Generation Schemes - Site and Economic Viability
O)
landfill Start Up Date Quality and Quantity
of Gas Used
Allsopps Hill October 1989
Applcy Bridge No 1 engine 54-56% CH4
March 1990 1 ISOm'/hr at 60mBar
No 2 engine suction
October 1990
'I' Field Slcwartliy March 1987 40%-50% methane
content
330lcepa
(300 m'/hr)
Mcridcn (Packinglon) Oclober 1987 60% methane content
although it can run on
40%. Minimum of
3400m'/hr
Power Generation
2MW
2MW
!7.6GWIir to
December 1989
(internal power
combustion 10%)
June '88-Junc '89.
Gross generation
19.34k\Vh. Actual
export 3.5-3. 7MW.
(internal power
consumption 17%)
Operational Payback
Availability Period/Cost
—
No 1 engine over 1 In fourth year
year 85%.
No 2 engine over 4
months 97%
Up to December 2.6 years
1989. 3 units have £418,470
completed 22000 (contract cost)
. hrs. Service factor
95%. Capacity
factor 91%.
Running load
(overage 266k W)
June '88-June'89. 5 years £1.94m
Service factor 90%.
Capacity factor 61%
Other
Comments
-
Brickworks and
10% to Easlem
Eleclricly
Energy savings
are equivalent to
96000 GJ/yr
Specific cost per
unit output
£654ftW (1988)
Reference
Good (1990)
Thomas (1991)
Ewbank Prcecc
Ltd (1990)
Homsby (1990)
Homsby (1990)
-------
Table D2 - Utilisation for Electricity Generation Schemes - Site nnd Economic Viability (contd)
m
Landfill Swrt Up Date Quality and Quantity Power Generation Operational
of Cos Used Availability
Oncrspool June 1986 25-50% Methane IMW
content
SinncPil(l) April 1989 30-45% Methane IMW
content
Slonc Pit (21 Autumn 1989 42-52% methane I.3MW
content
Wapscy's Wood October 1987 Runs on 28-55% I.2MW Thermal efficiency
methane, and > 10% of engine is 40.%.
pilot fuel Operational
availability 90%.
Payback Other
Period/Cost Comments
3 years Gas engines arc
£525.000(1986 capable of
price) operation with
methane as low
as 25% (Usually
«el at 28-35%)
Savings in the
region of 2.75M
units electricity/
year at an
average price of
4.3p/kWh
Provides 40% of
electricity used
£900.000(1987 Energy savings
prices) in region of
260,000 OJ and
£660.000 (1987
price*)
Reference
Matan (1988)
Robinson
(1990)
Robinson
(1990)
Limbrick
(1990, 1991)
-------
Table D3 - Utilisation Information for Direct Use Schemes - Site and Plant Details
Landfill Site Operator Type of System
HI Avclcy Aveley Methane Ltd Combined cycle CHP
g£ plant with a Ruston TB
5000 gas turbine.
lOOOOrpm. Hot
exhaust gases from (he
gas turbine arc ducted
to an existing high
pressure water lube
boiler.
Bidston Moss Bidstone Methane Multi fircd maxccon
shell boiler rated al
30.000lb/hr wilh a
working pressure of
150 psig. Using
landfill gas as main
fuel supply.
Bilham Quarry Lemacc Lid Secondhand Ideal
Brodsworth Standard Britannia
Boiler wilh a fully
automatic Wcishaupt
dual fuel burner.
End Use Observed Problems Service Period Reference
Purflcel Board Mills 133 hours shutdown — NIFES (1985)
boiler (waler lube) due to control oil Thermal Dev Ltd
system. (1990)
Premier Brands Ltd No evidence of — NIFES (1988a)
Boiler (shell), landfill corrosion or other (1988b)
gas 2.5km to n shell major faults.
steam boiler which is
used for food
production.
Lemace Ltd Boiler. - - Davies (1990)
Uses landfill gas to
power boiler which is
used for heating
greenhouses for flower
and vegetable crops
-------
Table D4 - Utilisation Information for Direct Use Schemes - Site and Economic Viability
Landfill SUrt Up Dale Quantity of Gas
Used
m
j^ Avelcy December 1987 20000 Icepa
<0 (ISOOm'hr)
Bidslon Moss November 1989 4IOOtccpa
(370m'hr)
Bilham Quarry 1985 3244CJ
Brodsworth
Power Generation
2.97MWof
electrical power.
63.5 lonncs/h boiler
power. 30%
efficiency of
electricity
generation
5MW
0.06MW
Operational Payback
Availability Period/Cost
8400 hours £2.7 million
96% availability 2.8ycars
77% thermal 3-3.6yrs
efficiency
98% in 1 year
55% thermal 2-3 years
efficiency
Other Comments
Energy savings in
region of 3.05M
therm/yr or 12200
tcepa and
£970,000/yr
Energy «aving« in
the region of £21-
47,000/yr
Energy «aving«
amount to
23IOOGJ/yr«nd
£11.500
Reference
NIFES (1985)
Thermal Dev Ltd
(1990)
NIFES (I988a)
(1988b)
Dnvies (1990)
-------
APPENDIX F: MAKING LANDFILL GAS AN ASSET (Paper)
Tudor D. Williams
Solid Waste and Power
July/August 1992
(page 22 to 29)
© 1992.
Reprinted with permission from Solid Waste & Power magazine,
HCI Publications, Kansas City, MO.
F-1
-------
Meeting Regulations
Making Landfill Gas an Asset
Facing new requirements for controlling landfill gas, many landfill owners
are eager to turn the liability of the gas into an asset. A common approach-
installing a gas-to-energy plant—is only one of several options for beneficial
use of landfill gas.
By Tudor D. Williams
I his summer, the Environmental
Protection Agency is due to issue new
regulations requiring control of gas
emissions from munidpal solid waste
landfills. The prospect of these rules is
spurring many landfill owners to ex-
plore the beneficial energy uses for the
gas. The thinking is that—since the
gas has to be collected and controlled
anyway—it might as well be put to
good use.
This article provides a brief over-
view of the options landfill owners and
project .developers have for simulta-
neously* meeting environmental con-
cerns and improving the economics of
their landfill projects.
Landfill Gas Collection &
Generation
Landfill gas is collected under a
vacuum through a system of valved
horizontal and/or vertical (slant) wells
connected to a header (collection pipe)
system arid blower. Besides recover-
ing gas for beneficial use, the collec-
tion system can be designed and op-
Tudor Williams is a partner in
Cambrian Energy Systems. Cam-
brian Energy Systems has devel-
oped more than 20 landfill gas-to-
energy projects.
This article has been evaluated
and edited in accordance with re-
views conducted by two or more
professionals who have relevant
expertise. These peer reviewers
judge manuscripts for technical
accuracy, usefulness, and overall
importance within the field of solid
waste management.
The Puente Hills landfill, operated by the Sanitation Districts of Los Angeles County, bums
landfill gas in oversize boilers equipped with flue gas recirculation. Recirculating the flue gas
achieves low NOx emissions. The facility produces 50 MW of power, enough to power
100,000 homes.
crated to assist in preventing off-site
migration of gases. The collection
systems must also be controlled to
minimize air intrusion, which will affect
the useful quality of the gas and can
contribute to underground fires.
Details on the design and operation
of collection systems are beyond the
scope of this article. However, as a
general gauge for estimating project
feasibility, see the accompanying story
on landfill gas generation, "Estimating
Gas Generation Rates."
Cleaning Up the Gas
Gas collected from MSW landfills
usually requires some level of cleanup
or treatment before combustion.
Among the reasons for treating the
gas are: to limit releases of pollutants
to the environment; to prepare a
medium-grade gas that will not cor-
rode the reciprocating engines and
other equipment used in energy pro-
duction; and to upgrade the gas to a
high Btii, "pipeline quality" natural
gas. Landfill gas can be burned in" a
boiler without pretreatment; the
combustion process destroys most of
the trace constituents.
The gas has a typical composition of
40 to 60 percent methane (CH,), 40>to
50 percent carbon dioxide (COJ, and 1
to 2 percent air and inert gases. The
22 SOLID WASTE & POWER/JULY/AUGUST 1992
F-2
-------
Table 1: Costs and Emissions for Selected Landfill Gas-to-Energy Power Options.
Technology
Internal Combustion
Engine (2MW + )
Gas Turbine
(2.7 MW + )
Boiler
(10MW + )
Organic Rankine
Capitol
Costs
(perkW)
$1.000-1.200
$1,000-1,500
$1,000-1.500
$1.000-1.500
Operations &
Maintenance
(e per kWh)
1.4-2.0
1.0-1.5
0.5-1.8
0.5
Heat Rate
(Btu/kWh)
10,500-13.000
14,000-15,000
11,300-14,000
15.500
Emissions (Ibs/M Btu)
NOx CO HCI
0.22
0.07
0.045
0.05
0.671
0.10
0.005
0.19
0.147
0.007
0.050
0.45
Ibs/M Btu = pounds per million Btu: kW - kilowatts; kWn = kilowatt-hour
gas also contains other impurities,
totalling between 500 and 5,000 parts
per million (ppm) by volume, and
condensate.
Methane in the atmosphere absorbs
heat 20 to 25 times more effectively
than does C02. Because of this abili-
ty—and concerns about its contribu-
tion to: global warming—EPA has pro-
posed requiring combustion of meth-
ane. However, to control NOx and CO
while burning methane for power pro-
duction, operators may need to use
catalytic converters on the engines to
clean up the post-combustion gas.
To date, however, exhaust catalysts.
have not been successful on landfill gas
because some trace components in the
gas, particularly silica, mask or coat
the catalysts and prevent them from
functioning properly. Filtration and
washing can minimize silica coming
from dust, but methods for managing
silica from the oxidation of silicone-
based compounds, which have vapor
pressures similar to water, have yet
to be developed.
The trace impurities in landfill gas
include a wide range of .hydrocarbons,
volatile solvents such as benzene,
organic sulfur compounds, hydrogen
sulfide, silicon-based compounds, and
other compounds. Since some of these
compounds are carcinogenic, various
state and federal rules require emis-
sion concentration studies, health risk
assessments, and collection and com-
bustion of landfill gas.
Managing Trace Components
Refrigeration, activated carbon fil-
tration, water washing, and washing
processes using Selexol® solvent or
specially formulated glycol are among
the methods currently used to remove
the trace components from landfill gas.
This fall, Bio-Gas Development,
Inc., of Atlanta, working with Pacific
Energy, will demonstrate a new trace
component removal system that will
pretreat gas recovered from the Pen-
rose Landfill in Sun Valley, California,
a suburb of Los Angeles. The treated
landfill gas will be used in an. EPA-
sponsored fuel cell project. Bio-Gas'
system, called GPS HI, will use a
combination of absorption and .de-
hydration beds and very .low temper-
ature to remove water and trace con-
taminants, including the silica com-
pounds. It is designed to treat
contaminants comprising up to about 1
percent of the gas volume.
Managing Condensate
During collection, the temperature
of landfill gas will drop significantly as
the gas is drawn from inside the
landfill (where temperatures typically
reach more than 100°F.) Due to this
change in temperature, water vapor in
the gas condenses, creating a conden-
sate composed principally of water,
with traces of organic and inorganic
compounds. This emulsion may sepa-
rate physically into two phases: an
aqueous phase and a floating hydro-
carbon phase. The hydrocarbon frac-
tion, which may comprise up to 1
percent or more of the liquid, is
sometimes collected and sold as a
light industrial fuel.
Condensate is managed in one of
two ways. It can be returned to the
landfill and managed under, the Re-
source Conservation and Recovery
Act. It also can be managed under the
Clean Water Act, if it is treated and
discharged as effluent to a waterway,
or indirectly discharged through a
public treatment works. The cost for
condensate disposal can vary wide-
ly— ranging from less than 1 cent
per gallon for sewering, to as much as
$1.50 per gallon for; trucking to a
remote site.
Utilization of Landfill Gas
Several applications for using landfill
gas have emerged in recent years.
Many of the beneficial options are
presented in the following.
Power Production
Electrical power is currently pro-
duced from landfill gas at more than
100 landfill sites. In most of these
applications, a power plant is located
on the landfill site and the electric
power produced is sold to the local
utility under a long-term contract.
Some power purchase agreements
for landfill gas projects are written to
displace retail power (that would oth-
erwise be purchased by the owner of
the landfill gas project), some are
levelized sale contracts (usually with
the utility paying higher rates early in
the term), and, in a few cases, power
is wheeled to a utility other than the
local utility. But most projects market
power to the local utility for the utili-
ty's avoided cost (rate can change over
time). The challenge is to develop
landfill gas power projects that can be
competitive with current energy prices,
which have been depressed for several
years.
Power is generated using a variety
of prime movers, including reciprocat-
ing engines, gas turbines, and steam
turbines. The power options in com-
mon use at landfills are summarized in
Table 1. In addition, researchers are
experimenting with fuel cells as power
generators.
Reciprocating Engines. The vast
majority of projects have been imple-
mented with reciprocating engines.
There are some new power generation
systems being introduced into the
24 SOLID WASTE & POWERAFULY/AUGUST 1992
F-3
-------
Estimating Landfill Gas Generation Rates
-• ••'- •••:•:...:- ..iv^-.-y.-. .;. • .-^;V;.:- :/•'•••••" " . ' '..'
The three chiefvelemental cohstitijents .of municipal solid waste are carbon,
oxygen;-and.^hydrogen. Some;nitrogen:1 and a little sulfur, are also present.
:-Through microbiological fermentation, or anaerobic decomposition, these five
V.cpnstituerits ir^;likely to prpdubei fourgases: chiefly carbon dioxide (CO?) and
•methirie;;.'• -•. :. • ••.-••:;..
;^:SinciB\eC)2"1§! produced .under, both 'aerobic and anaerobic (lacking oxygen)
i-'cbriditionsTand'iCHt from the ' latterf the'production of'COa.is highest in the first
months pta. laihdfiH's; existence. As CC>2 production declines, CH4 production
*nses;::-EvenhJa]|y^YYith'in one.tp .three years-^oth are produced in relatively
egua|}arriouhtsjand each makes up,aboUt;45 to 50 percent .of total landfillgas
""'':'''' ''''''''':'' ''"'''
;.^ /A I4hdfil|..generates gases for extended-periods, insome;-cases for more
.'•:1hari?50^yearsX(fpr;>ery dry:,landfiljs), until most biodegradable material is
vv:.exhausted5''.pgi^rei>1j.shows"-gene.i^ize
-------
from the sale of electricity—more than
$42 million in the past year—covers
the gas system costs and yields a net
revenue to help reduce the tip fees at
Sanitation Districts landfills.
Fuel Cells. Fuel cells, which chem-
ically convert methane directly into
electrical energy without combustion,
are currently a "gee whiz" technology.
To date, the technologies tried have
worked, but they are too expensive
for commercial application. Still re-
search continues, mainly because fuel
cells can produce as much as 40 per-
cent more energy from the same
volume of gas as competing technolo-
gies.
Late in 1992, International Fuel
Cells of Windsor, Connecticut, will
test a prototype cell at the Penrose
Landfill gas project operated by Pacific
Energy. IFC's system converts
methane to power at; low tempera-
tures, ^and therefore, produces very
low emissions. The fuel cell cost is
very high—approximately $2,500 per
kilowatt—but with volume production,
the price should come down.
Industrial Fuel
Landfill gas has been used success-
fully for 10 to 15 years as a replace-
ment or supplement to industrial fuels
including natural gas, fuel oil, and coal.
The applications include steam pro-
duction, brick manufacturing, cement
production, glass manufacturing, as-
phalt production, utility power produc-
tion, and others.
The most common industrial fuel
applications are indirect uses where
the landfill gas is fired into a boiler or
other heat recovery device. For these
applications, the boiler or other unit is
sometimes retrofitted with a new
burner and a new fuel control system
to accommodate the lower Btu value
fuel. This retrofit can cost $150,000
per process unit (boiler, dryer, or
furnace). Often, less costly modifica-
tions are needed. These might include
changing to a double piping system to
feed landfill gas at a rate to match
required Btu input and adding a second
carburetor.
In certain applications, where the
modification costs are extraordinary, it
may be appropriate to process the
landfill gas to remove the COy-and
thus avoid the need to retrofit new
burners.
One long-running direct gas sales"
project is the GSF Energy plant at the
Mountaingate Landfill in West Los
Angeles, California. Since 1984, the
University of California at Los Angeles
(UCLA) has used gas generated by the
landfill to fire two boilers. One is fired
exclusively with landfill gas, the other
burns a mixture of landfill gas and
natural gas. To prepare the landfill gas
for use in UCLA's boilers, GSF chills
the gas to knock out condensate,
compresses it to pipeline pressure.
then uses the Selexol® solvent process
to remove impurities. The resulting
fuel is a medium-Btu fuel, 'about 500 to
550 Btu per standard cubic foot (scf).
The gas is piped 4 miles from the
landfill to UCLA.
Pipeline Gas
Several proven technologies exist to
process landfill gas into a high Btu fuel
suitable for use in natural gas pipe-
lines. These technologies remove
trace contaminants and the C02 to
deliver a gas between 940 and 960
Btu/scf. After treatment, the gas typ-
ically contains 4 to 5 percent nitrogen
and 1 percent C02, with the balance
being methane.
While landfill gas is readily proc-
essed into pipeline gas, there is a
concern over future environmental
regulations regarding the trace con-
taminants from the landfill gas. Cur-
rently, there are no national guidelines
for acceptable levels of trace contami-
nants. However, California is devel-
oping guidelines that would make it
very difficult to market processed
landfill gas to pipelines for general use.
The proposed guidelines have included
very stringent standards for some
compounds; for example, the limit on
vinyl chlorides is 1 part per billion.
Available treatment systems can con-
trol vinyl chloride concentration to
approximately 1 part per million.
When issued, the California guide-
lines may influence adoption of stan-
dards in other states or at the federal
level. Conversion to natural gas
promises to be a very good, econom-
ical use of the resource in the long
term; however, the nature of envi-
ronmental regulations and their im-
plied risk will determine the viability of
this market.
28 SOLID WASTE & POWER/JULY/AUGUST 1992
F-5
-------
Compressed Vehicle Fuel
When processed into pipeline qual-
ity gas, landfill gas is compressed to
300 pounds per square inch (psi). This
gas can be further compressed to
2,500 psi for storage in cylinders and
used to operate motor vehicles. For
compressed vehicle fuel, membrane
systems, like that produced by W.R.
Grace, provide economical C02 sepa-
ration. More than 40,000 vehicles
have operated with conversion kits for
a dual fuel system using compressed
natural gas with gasoline as the stand-
by fuel. Conversion kits contain stor-
age tanks, valves, and carburetors
that parallel the vehicle's current gas-
oline delivery system. Cars have op-
erated on processed landfill gas from
the Penrose Landfill. Pacific Energy
scrubbed the gas using'a water wash
system known as Binax* and then
compressed it.
Low ertiissions, low maintenance
costs," and;, fuel cost savings are the
benefits of this application. Capital
costs and fuel logistics are the draw-
backs. Fleet uses, such as school
buses or delivery fleets with a com-
mon parking area, have been the major
application of this technology.
By the end of this year, the Sanita-
tion Districts of Los Angeles will begin
testing compressed landfill gas as a
vehicle fuel. Preparation of the gas will
include filtering through a semi-perme-
able membrane. If successful on
medium-duty demonstration trucks,
Sanitation Districts officials hope to
offer the fuel to trash haulers that
serve the Districts' landfills.
Liquid Vehicle Fuels
Landfill gas can be used as a feed-
stock for methanol and diesel produc-
tion. However, most methanol and
diesel process technologies require
that the landfill gas be processed to
pipeline quality before burning it in
systems with catalytic converters. The
application is driven by economies of
scale of the process technology and
the feedstock costs. Questions re-
garding the economic viability of this
process will be addressed soon. Early
this year, Fuel Resources Develop-
ment Company of Denver, began
producing a diesel fuel substitute from
gas collected at a landfill in Pueblo,
Colorado. The project is designed to
produce 235 barrels of fuel per day;
currently the system is using a mix of
40 percent landfill gas and 60 percent
natural gas.
Liquefied methane is another prod-
uct made from landfill gas that should
be demonstrated soon. This tech-
nology should produce a clean fuel with
very low pollution and high storage
density (about six times that of com-
pressed natural gas). EcoGas of Austin,
Texas is planning several projects that
will convert landfill gas into liquefied
methane.
Tax Incentives Continue
The federal government has recent-
ly extended a price support for landfill
gas utilization known as a production
tax credit (Section 29 of the Tax
Code). The windfall profits tax legisla-
tion in 1980 originally established
these landfill gas tax credits. The
credit is currently $0.94 per million
Btu. The credit begins to phase out as
oil reaches a limit (currently $40 per
barrel) and completely phases out as
oil reaches a second limit (currently
$50 per barrel).
Private sector developers use these
credits to provide a return on other-
wise marginal landfill gas projects dur-
ing periods of depressed energy prices.
To qualify for the credits, a collection
system or a process facility needs to
be in place before January 1, 1993.
The credits, which extend through the
year 2002, are based upon Brus sold
to that date unless the price of oil
exceeds the specified limits.
Conclusion
Landfill gas, if uncollected or uncon-
trolled, represents an environmental
liability—and a lost opportunity. The
best use of this resource is to recycle
it into a marketable energy product.
Such projects not only help preserve
our environment, but reduce our reli-
ance on other energy resources. Often,
the activity takes vision and persis-
tence, but the number of operating
projects and continuing research illus-
trate that more options exist than ever
before, and the rewards are there, n
Mr. Williams can be reached at
Cambrian Energy Systems, 3420
Ocean Park Blvd., Suite 2020,
Santa Monica, CA 90405; (310)
314-2727.
SOLID WASTE & POWER/JULY/AUGUST 1992 29
F-6
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APPENDIX G: LANDFILL GAS RECOVERY SYSTEMS FOR EXISTING LANDFILL SITES
(Presentation)
Richard L. Echols
Managing Director Energy Recovery Operations
Browning-Ferris Gas Services, Inc.
Presentation to the ASCE
(American Society of Civil Engineers)
14 September 1992
(shortened)
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LANDFILL GAS RECOVERY SYSTEMS
FOR EXISTING LANDFILL SITES
INTRODUCTION
Landfills that bury materials which decompose soon develop an anerobic (without oxygen)
atmosphere. Decompositon of the waste and subsequent bacterial action produce landfill gas as
a waste product. This gas is typically 50 to 55% methane and 45 to 50% carbon dioxide along
with many different non-methane organics in the part per million concentrations.
The amount of landfill gas and the length of time that landfill gas will be produced are both
subjects of great debate among experts in the field. Production assumptions that range from 2.5
to 4.5 standard cubic feet of landfill gas per pound of refuse that decomposes and continuing
decomposition for at least 30 years appear to be realistic ranges. 'Empirical production decline
curves have yet to be fully quantified because of a lack of long term data.
REGULATORY
Regulatory control of landfill gas is an ever changing and ever increasing fact. Because landfill
gas is malodorous, can carry toxic and/or carcinogic compounds, and has the potential to collect
in explosive concentrations, it has received a great deal of regulatory attention. At the Federal
level, the existing Subtitle "D", included in the original Resource Conservation and Recovery Act
of 1976, covers the migration (via underground routes) of and the collection of explosive
mixtures in buildings. The proposed new Subtitle "D" will strengthen this control. Proposed
regulations implementing the Clean Air Act will place rigorous landfill gas emissions control on
landfills with a capacity in excess of 167,000 tons. Landfill gas control rules and regulations at
the state level vary across the board from nothing to much more stringent that federal regulation.
Prior to the design and installation of any landfill gas system, it is imperative to check with local
WRE92045
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control agencies to obtain their latest version of rules and regulations. This will generally require
consulting the solid waste regulators, air quality regulators, health regulators, and regional and/or
state air quality regulators. Just because the solid waste regulators do not require a permit for
a landfill gas system, or issue a permit allowing passive vents, never assume the air quality or
health agencies approval will not be needed or their permitting process need not be followed.
A single action or construction project usually requires multiple permits before ground is
disturbed to avoid violations and fines. Many times these permits require much work and
expenditures of substantial monies to obtain.
LFG PRODUCTION
The questions of production versus collection has to be addressed. It is impossible to calculate
collection efficiency because the exact amount of landfill gas being produced is unknown. The
known parameter is the total flow as measured in the main collection pipeline, and that flow is
composed of landfill gas, infiltrated outside air, and air sucked in through any source for leaks.
The true measure of performance for a landfill gas collection system is its ability to meet its
design objectives. That is, are perimeter landfill gas monitoring probes clear? Are surface
emissions levels being met? Are odors from the site being controlled? In conjunction with this,
the landfill gas system should function in a reliable, dependable manner without excessive
operation and maintenance costs. Measured flow is always a better indicator of landfill gas
systems performance than are models which attempt to predict the quantity and duration of
landfill gas production within a landfill unit using a mathematical equation.
For a landfill with a comprehensive gas extraction system installed, Rgure 1 is a representation
of the amount of the landfill gas collected. During the start-up phase of landfill gas production,
there is an abundance of high percentage (48-58%) methane landfill gas. This is the accumulated
gas that has been produced over a long period of time in which gas has not been able to
completely escape the confines of the landfill. This gas is always under pressure, ranging from
a few inches water column to several hundred inches of water column. Landfill age, depth,
cover, and construction methods all influence the amount of pressure within.
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FIGURE 1
CD
i.
oo
<
o
O
LU
2
12
_J
O
ACTIVE LANDFILL GAS EXTRACTION SYSTEM
LANDFILL GAS PRODUCTION
STARTUP
PHASE
STABILIZATION
PHASE
2 DAYS
TO
12 MONTHS
N
X
X
ONGOING PRODUCTION
PHASE
2 DAYS
TO
3 MONTHS
20 YEARS
TO
? YEARS
TIME
BROWNING T FERRIS GAS SERVICES, INC.
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As more gas is removed from the landfill than is being produced, the stabilization phase of
landfill gas production begins. During this phase, it is critical that the gas extraction system be
adjusted continuously to avoid overpulling individual wells, or all of the wells at the same time.
Once this phase is entered, it generally only takes a few days for a sufficiently sized extraction
system to reach a fairly stable production rate. It is important to note that this phase can never
be reached if a gas extraction system is undersized. If the sizing is marginal, then the start-up
phase will be greatly extended as will the stabilization phase.
The ongoing production phase will be for the remaining life of the landfill. While landfill gas
is being extracted at approximately the same rate it is being produced (or manufactured) by the
landfill, many variations will be noticed. All of the many factors that influence a landfill's
ability to produce gas come into play. Flowrate variations will be noticed between daytime and
nighttime production, seasonally, changes in weather, etc.
The slope of the ongoing production phase curve is ever so slightly downward. Little, if any,
decline is noted in the first 3 to 8 years (depending on the length of system operation) for the
systems Browning-Ferris Industries, Inc. (BFI) has installed.
For landfills that have partial gas extraction systems installed, the production curve will still
apply. The phase definitions are not as sharp because the area of the landfill that does not have
gas control will continue to feed additional landfill gas through preferential flow paths to the area
of lower pressure because of the operation of a partial gas extraction system. Also, if an
operating landfill gas extraction system is shutdown for an extended period (more than a week),
it will go through these same phases when it is started up again.
LANDFILL GAS CONTROL
OBJECTIVES
Before setting the design pen to paper (or cursor to computer screen) it is necessary to set the
objective that is to be achieved by the landfill gas collection system. The following is a list of
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common objectives that landfill gas control is used and needed for:
• To control offsite, underground migration of landfill gas
• To control surface emissions of landfill gas
To control landfill gas odor
• Because an operating permit for a landfill has a provision which requires landfill gas
system installation
• Because a regulatory agency issues a ruling or directive ordering the installation
To develop a fuel source
• Any combination of these reasons or other reasons
All of these reasons are driven by the characteristics of landfill gas. It can gather in explosive
concentrations, be malodorous, or contain toxic and/or carcinogenic compounds. These
characteristics constitute hazards to the public health and safety, therefore, requiring control.
After discovering the reasons for a landfill gas extraction system, the design engineer faces
another set of physical, gas handling problems. Landfill gas always contains moisture, carbon
dioxide, and halogenated compounds, and almost always contains some Hydrogen Sulfide. These
are the exact ingredients needed to form "acid gas" or "sour gas", which is extremely corrosive
to equipment These ingredients also contribute to two phase flow in the piping system. These
physical problems must also be addressed in the design of the system.
Once the objectives for the landfill gas system are understood, the designer is in position to
consider which type of system is best for the application at hand.
PHYSICAL LOCATION CONSIDERATIONS
The physical location of a landfill and its type of construction play an important pan in the
selection of design parameters for landfill gas control. The most common types of landfills for
construction/location parameters are:
An all above ground fill
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Excavation with above ground fill
Completely below ground
- pit or quarry fill
Valley fill
- closed on all but one side
- extends above valley in height
Built up cell fill
The physical landfill type combined with the actual construction method of the landfill yield the
final pieces to the design puzzle. The actual landfill construction traits that the designer is most
interested in are as follows:
• Is there a bottom liner?; Yes?; No?; If yes, what type?
Was daily cover used?; Yes?; No?; If yes, what type?
• Is final cap in place?; Type; Thickness; Integrity
Is leachate extraction in place?; Yes?; No?; If yes, what type?
What kind of trash taken?
What kind of compaction?
The location and construction of the landfill combined with the surrounding population density
also will have some impact on the selected equipment, operation of the equipment, and the types
of alarms and safety devices used on major equipment.
G-7
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LANDFILL GAS EXTRACTION SYSTEM
JOB PROGRESSION
A systematic job progression always yields more consistent results .with a corresponding higher
quality product. After design and installation of over 50 systems, this author prefers using the
job progression as described in the following paragraphs:
Collection of Baseline Data
- Topographical information
- Property lines
- Adjacent properties
- Fill volumes
From this data, an accurate, up to date topography map can be generated for the top of fill as
well as the bottom of fill. All engineering quantities, calculations, and price estimates are based
on this information, and they will only be as accurate as the starting information.
Using the latest map information, generate a sketch of the system layout including
location of all facilities.
, This sketch will determine the number and location of landfill gas extraction wells, the
approximate location and length of all underground piping, drainage sump number and locations,
and the blower building and flare locations. Having previously determined the landfill depth, the
design engineer can now perform the pipe, blower, and flare sizing calculations. Additionally,
the type of sump system can be selected, sized, and priced. This basic design information can
be expanded by using limited details of individual parts, thus preparing a "Phase I" set of plans
for client review and ultimate submission to agencies for permit requirements.
• Develop bid level documents
While awaiting permits, the design engineer can develop the design and specification package
WRE92045
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further for use in the next project step, solicitation of construction bids. At this level, product
specifications need to be written for each material to be used. Along with this, installation
specifications, testing requirements, construction methods, product support, warranties, guarantees,
and start-up help need to be detailed. Each party needs to have a very clear understanding of its
responsibilities and authority, complete with the amount of dollars attached to eaeh. Careful
attention should be paid to how change orders are created, approved, and implemented. The total
bidding process should include the following action:
Send out bid solicitations
• Have a mandatory prebid meeting
• Send out required addenda to bidders
• Take bids on close date
• Evaluate bids and select contractor
Have a pre-construction meeting
It is best to wait until major environmental permits have been obtained before issuing the project
for bids. Permitting, especially multiple agency permitting, can be a long, slow process. In
nearly every case, an air permit and a solid waste permit will be required. After these, there are
any number of construction permits at the local level that the contractor should obtain. These
do not typically provide the level of difficulty involved in environmental permits.
• Develop construction documents
While the prints and specifications used for bidding are very detailed, these should be updated
to construction level by incorporating alternate bid products and manufacturers prints and
specifications that were provided by the winning bidder. These construction documents should
be placed in the contractors possession at the pre-construction meeting. By the end of this
meeting all parties should have a clear understanding of the construction management, work
areas, storage and staging areas, job progression, material handling, expense and payment
approvals handling, along with job safety.
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In summary, a landfill gas extraction job goes through three phases with key subsets of each
phase.
PHASE ONE
PHASE TWO
PHASE THREE
WRE92045
A. Data gathering
B. Preliminary design & approval
C. Major permit acquisition
A. Bid level specifications development
B. Bid solicitation, acceptance, and award
C.- Extraction system construction
A. System start-up and shake-down
B. Normal operation and maintenance
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LANDFILL GAS EXTRACTION WELLS
The gas extraction wells are one of the most important components of the gas extraction system.
The location and number of wells is dependent upon several variables. Site specific
characteristics including existing and final topography, location of benches or drainage swales,
limits of fill, and cell construction along with the area influenced by each extraction well are all
determining factors in well placement.
The manner in which gas extraction wells are designed, drilled, completed, and the quality of
materials used in the wellstring and related components directly affect the performance and
effective life of the well itself along with the entire gas extraction system.
WELL LOCATION AND SPACING
For complete landfill gas control, a comprehensive wellfield should be used. By installing wells
in all areas of trash placement, true landfill gas control can be achieved. Central wells do the
bulk of the extraction work while perimeter wells provide the final "ring" of control. These wells
all feed into a common header/blower system.
Perimeter wells serve to form a vacuum net around the filled area, preventing any gas generated
within the placed refuse from escaping or migrating offsite. Spacing of these wells will be
between 150 and 250 feet well to well but not further than 150 to 200 feet horizontally from the
limits of trash. Locating this first row of wells far enough inside the filled area assures the well
will be able to be drilled to the maximum depth of the cell.
Gas extraction wells to be placed in the interior of the landfill will be spaced on 300'. to 350'
centers. These interior wells collect the bulk of the landfill gas as they are located where the
principal quantity of landfill gas is generated. The possibility of air intrusion into central wells
is reduced because the amount of surface area from which air could be drawn, (i.e.: the side
slopes & cap), is minimized as compared to perimeter wells. It is for this reason the interior
wells can generally be operated at higher vacuum and flowrates and still maintain high (45% -
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FIGURE 5
I2'-0'±
GRADED SOIL
BACKFILL \2~ WIN.
u- I I
O I <->
CLAY BACKFILL OR WELL
GRADED SOIL BACKFILL
4'BENTONITE PLUG - USE-
APPROXIMATELY 25 SACKS
OF BAROID 'BENSEAL1 OR
APPROVED EQUAL.
HYDRATE BENTONITE WITH
5 GALLONS OF WATER PER
SACK DURING INSTALLATON.
ISOLATION LAYER - USE —""
ONE SACK OF 3/8' BENTONITE
CHIPS (BAROID 'HOLEPLUG* OR
APPROVED EQUAL)
••.I.'.';-.
HEADER
—3' BENTONITE PLUG - USE
APPROXIMATELY 18 SACKS
OF BAROID 'BENSEAL1 OR
APPROVED EQUAL. A MINIMUM
OF 241 TO BE IN CONTACT
WITH EXISTING COVER OR
CAP IF POSSIBLE.
HYDRATE BENTONITE WITH
5 GALLONS OF WATER PER '
SACX' DURING INSTALLATION.
61 DIAMETER SDR-17 HOPE
ORILL ( 8 )'/V DIA.
HOLES EVERY 6' FOR
ENTIRE PERFORATED
LENGTH
- I '/21 DIA. WASHED RIVER GRAVEL OR
ACCEPTABLE CRUSHED STONE
TO EXTEND TO A MINIMUM OF I FT.
ABOVE TOP PERFORATION.
• 6- DIA. SDR-17 HOPE FUSED CAP
I
36'
TYPICAL ABOVE GROUND GAS EXTRACTION WELL DETAIL
NOTE I: ADJUST PLUG AND BEDDING HEIGHTS AS NECESSARY
TO MEET ACTUAL FIELD CONDITIONS
BROWNING - FERRIS GAS SERVICES, INC
G-12
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Ol
J
a
SI
xi
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50%) methane concentrations.
In either case, perimeter or interior wells, it is desirable that the well be drilled as close to the
bottom of trash as possible. At any landfill, drilling will be halted at no less than 10 feet from
the elevation of the existing cell liner to avoid liner damage. The existing liner or bottom of
placed trash elevations will be obtained from as-built drawings prior to the drilling operation.
BFI is currently successfully operating many gas extraction systems designed and built with this
same perimeter/interior well field layout. These systems have all effectively controlled offsite
landfill gas migration as well as helped control odor and/or vegetation distress problems
associated with landfill gas. These same wellfields also supply fuel gas to energy recovery
projects.
The "radius of influence" a well exerts is an approximated measure of the lateral distance the
vacuum the well introduces into the landfill can induce flow of the gas produced within the
landfill. It must be noted that this is a misleading term. At best, radius of influence is a gross
approximation. It is observed that some gas near wells will escape into the atmosphere (not be
collected) and that some gas outside the expected radius of influence will be collected by the
extraction well. In actual practice, the area of low pressure created by the well provides the path
of least resistance for the gas to flow. This preferential flow causes gas to flow to the wells even
though the vacuum area is limited. The phenomenon causes the "radius of influence" calculation
to be very misleading in that one well can "influence" an entire landfill because of'the
preferential flow paths created. As the thickness and quality of top cover, side cover, and bottom
containment increase, the required number of extraction wells decrease. Most older landfills
require the well densities discussed in this paper due to cover constraints.
By creating zones or areas of low pressure within the landfill, preferential flow paths are set up
on an inward gradient, and with time, landfill gas will use these paths to flow inward rather than
being pushed out and away by internal pressure within the landfill. It must be recognized that
it takes time to create these flow paths with the wellfield, just as it took time to create the
pressure within the landfill.
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LANDFILL GAS EXTRACTION WELL CONSTRUCTION
Each gas extraction well consists of several components; 36" diameter well bore, gravel pack,
6" diameter high density polyethylene well pipe, two sample ports and a 4" ball valve.
The 36" diameter well bore is drilled the total depth of placed trash, minus 10' to ensure the liner
is not damaged. While drilling rates may vary according to the type of material drilled, 100* to
120' feet of drilling per 10 hour day is expected. The 36" diameter well bore allows a much
larger active circumference (9.42 If versus 6.28 10 than the more commonly used 24" diameter
well bore. Due to intermediate or daily cover within a completed landfill cell, perched water
may be encountered during the drilling operation. Utilization of the 36" diameter well bore
allows the driller to step down to a smaller bucket size to punch through the obstructing material
and allow the total depth of the extraction well to be reached. It should be noted that if areas
within the landfill have a large amount of water, wells may "water in". Physically, water rises
to a level in the well and cuts off a large majority of the perforated length of pipe. In such
cases, another well should be drilled in close proximity to ensure adequate extraction coverage.
When the well is drilled and the total depth reached is known, the correct amount of perforated
and solid pipe is fused together and "run" into the wellbore. BFI uses 1/2" diameter perforations
with a density of 16 holes per foot. A basic rule is that 1/3 of the well is solid pipe and the
remaining 2/3 is perforated pipe. This ratio is modified as wells become more shallow. In all
cases however, BFI strives to maintain at least 20 feet of solid pipe at the top of each well: A
HDPE cap is fused to the bottom of the pipe and a 6" X 4" tee is fused to the top of the well
pipe which extends about 3' above grade. Utilization of high density polyethylene pipe for the
well pipe and all related fittings provides the flexibility and corrosive resistance needed in a
landfill environment.
It is easy to say, "drill the landfill gas extraction well here". Prior to starting the actual drilling
process, it is important to have a drill rig that is capable of getting the job done, and having a
crew that is trained in the operation of that specific drill rig. Depending on well locations, it may
be necessary to perform ground preparation to allow drill rig ingress, egress, room to safely
WRE92045
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setup, and room to discharge and remove the exhumed trash as drilling progresses. The type of
drill bit that is used is very important to the success of the landfill gas well. Auger bits tend to
force the disturbed material in to the side walls of the borehole. As drilling progresses through
wet zones and through areas of daily cover, an even more impermeable layer is created in the
wellbore. This creates a well which will never produce the quantities of landfill gas that a
properly drilled well will produce. Using a core barrel drill bucket, with staggered
cutting/ripping teeth will produce a wellbore that is ragged and much more permeable. This hole
will also require about 20% more gravel and seal material than a straight volumetric calculation
indicates, because of the ragged and less dense wellbore.
After total depth has been reached, the required length of solid and perforated HDPE, complete
with the valve tee, should be fabricated and run in the hole. A small amount of gravel, one to
one and one-half yards should be added, then light of tension added to keep the pipe centered
in the wellbore. The remaining gravel (always, washed \-\W diameter) should be added with
care being taken to keep the pipe centered in the wellbore. Immediately pour about 5 gallons
of water to wet the stone, then add one bag of chipped bentonite. This bentonite sticks to the
wet stone, hydrates, and forms a protective layer above the stone to keep the upper wellbore
materials from sifting down into the stone, reducing permability, and limiting the wells ability
to produce landfill gas.
In order for the well to function properly, an effective seal must be placed above the perforated
zone. This seal must have the ability to form an airtight bond with the HDPE pipe and against
the ragged edge of the wellbore. This is accomplished by pouring two bentonite seals,'one above
the gravel zone and one at the top of the wellbore which ties into the landfill cap, and filling the
central zone of the wellbore with well graded clay and/or soil backfill. Care must be taken to
add five gallons of water per sack of bentonite place downhole. The bentonite, to be successfully
used, must be small pelletized granules/which allows dry pouring with water added and hydration
downhole for maximum sealing ability. Tremie pipe placed, pre-mixed bentonite has very poor
downhole sealing ability and is extremely difficult to handle.
A 4" PVC ball valve is then installed on the 4" branch of the 6" X 4" tee of the well pipe. This
WRE92045
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valve allows isolation and throttling of each well. Throttling is a means of adjusting the
extraction rates by controlling the amount of vacuum applied. The PVC body and viton seals
of the well valve have proven to be extremely corrosion resistant and effective on similar gas
extraction systems while offering the large degree of adjustment necessary to balance the entire
wellfield.
A 6" PVC cap is placed on the top of the well pipe extending above grade. The PVC cap is
removable to allow for measurement and pumping of water within the well if necessary, and for
checking the condition of the well.
Two stainless steel sample ports are threaded into the wellpipe to allow measurement of percent
methane, vacuum, temperature and flowrate. A 1/2" stainless plug is removed from the 3/4" X
1/2" bushing for testing purposes, thereby minimizing wear on the HOPE threaded holes.
A 4" kanaflex hose makes the final connection between the extraction well and corresponding
HOPE lateral piping. • This material is flexible to allow for the settlement and subsequent
misalignment between the lateral piping and well head assembly due to landfill settlement,
temperature expansion or contraction, or any other reason.
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LANDFILL GAS EXTRACTION
HEADER AND LATERAL SYSTEM
The header and lateral piping system is designed to minimize the impact on the daily operation
of the landfill while .also insuring that both a reliable and effective system is installed. Actual
pipe alignment may be adjusted in the field by the engineer. These changes would be to
eliminate any unforeseen problems and to insure the most efficient use of topography and other
existing conditions. Projected profiles for the header and subheader pipes are shown based on
existing topographical data, but actual pipeline profiles may require field modifications to insure
that the system is built in accordance with the intentions of the design. Some of the major design
considerations and requirements for this system are:
1) All pipe is to slope toward condensate sumps at a minimum grade of two percent.
2) A minimum amount of piping is to be placed in the areas which are to receive a synthetic
cap, thus minimizing the number of potential problems that may have to be repaired and
require disturbing the synthetic cap material.
3) All pipe is to have a minimum of two feet of cover.
4) The side slopes of the landfill are to be used whenever possible to establish the minimum
required pipe grades. By doing this, the number of required condensate sumps is reduced
dramatically.
5) All sumps are located in waste to reduce the need for dual containment and the associated
cost.
6) Never use 4" or smaller diameter pipe in the horizontal position for gas collection pipe.
PIPE SIZING
Blower and pipe size calculations are based on the Darcy-Weisbach equation for friction loss.
Maximum gas production is estimated to be 1.5 cfm per foot of perforated pipe. Past experience
with landfill gas extraction systems has shown this to be a conservative estimate. Pipe sizes are
selected by restricting the maximum allowable friction loss to 1 inch of water column per 100
feet of pipe. Pipe sizes are adequate to transport both the liquid condensate and the landfill gas.
WRE92(W5
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Blowers are sized to produce a minimum vacuum of 5 inches of water column at the most distant
well.
PIPE MATERIALS
All underground pipe and fittings are to be constructed of SDR 17 high density polyethylene
(HOPE). HDPE is considered by many in the industry to be the best material for landfill gas
applications because it is highly resistant to the corrosive nature of landfill gas and condensate.
Also, because of its' flexibility and durability, HDPE is well suited to withstand the stresses
imposed by the differential settlement within the landfill.
PIPE CONSTRUCTION
All HDPE pipe is to be joined using the butt (heat) fusion technique whenever possible. Butt
fusion is the preferred method for joining high density polyethylene pipe. It is a highly efficient,
economical method for joining HDPE that results in a joint that is stronger than the pipe itself.
It has been an accepted procedure in the gas and municipal service industries for nearly 20 years.
The principle of heat fusion is to heat two surfaces to a fusion temperature, 'then make contact
between the two surfaces and allow the two surfaces to fuse together by application of pressure.
On cooling, the original interfaces are gone and the two parts are united. Nothing is added to,
or changed chemically, between the two pieces being joined.
In areas where the butt fusion technique is neither feasible nor practical, flanged connections are
to be used. Typically, one flanged connection is placed on each tee. Flanged connections are
also used at valves and other fittings as required to facilitate the construction of the pipeline. In
order to help prevent corrosion related problems at the flanged connections, only coated ductile
iron back-up rings or 316 stainless rings and 316 stainless steel bolts are to be used.
All HDPE fittings are manufactured. BFI does not allow any field fabricated fittings because of
the high failure rate, nor any saddle weld fitting because of the same problems.
WRE92045
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LANDFILL GAS CONDENSATE
Landfill gas is typically saturated at its existing temperature and pressure within the landfill. The
gas is produced by inducing a lower than atmospheric pressure (a vacuum) on the landfill. This
lower pressure combined with the cooling induced by the gas flowing through pipe expansions,
contractions, and valves, along with lower ambient temperatures outside the landfill causes
moisture to condense from the gas stream. The piping system transferring the landfill gas and
entrained condensate maintains a minimum two percent downward slope, thereby utilizing gravity
to transfer the liquid condensate into dedicated sumps which are strategically positioned around
the base of the landfill.
CONDENSATE SUMP DESIGN
Condensate sumps, located in topographical lows, are a vital pan of the landfill gas extraction
system piping network. Early extracton systems used a "barometric" drain which returned the
condensate to the landfill. Because these were open to the atmosphere and to the landfill,
continued operating problems from settling, flooding, drying, and plugging occured. BFI now
uses a vertical sump, constructed of HDPE, and operated at line pressure. With the use of an air
operated or electric pump, this sump is well suited for automatic operations. Service is quick,
simple, and done without need of confined entry. For sumps that are located in virgin soil,
double containment can be added.
CONDENSATE DISPOSAL
The condensate collected within the sumps can be individually collected and/or pumped to central
tank for further handling or treatment. The condensate will be analyzed for TCLP parameters
on an annual basis to determine the regulatory status of the liquid. Previous TCLP testing at
similar BFI landfills has indicated that the condensate will not be hazardous. Typically, after
testing, the nonhazardous condensate will be pumped into a transfer truck for subsequent disposal
at a local wastewater treatment facility. Previous experience has indicated that this wastestream
can be treated efficiently without causing any adverse effects on the wastewater system.
WRE92045
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FIGURE 11
NOTE:
HOSE CONNECTIONS TO FORCE UAW
AND AIR HEADER ARE NOT SHOWN
IN THS VIEW.
— VALVE CONTROL —HELL ENCASEMENT
; KEY EXTENSION
UJUN GAS HEADER
5
Col
<-HOPE ffi TO SLOPE-
IT A UINIUUU Of
TOWARD SUMP.
NOTE:
PUUP MOSES ARE NOT
SHOWN IN THS VIEW.
IJ-HDPE SOR-l?
./ FUSED CAP
-8'xlO'INCREASE/!
-lO'xiriNCREASER
-CEUENT/BENTONITE GROUT PLACED
BY SIDE DISCHARGE TftEME PIPE:
94 LBS. PORTLAND CEMENT
5 LBS. POWDERED BENTOMTE
6 GALS. WATER
- 2V OIA. BORE
HOLE
SINGLE CONTAINMENT CONDENSATE PUMP STATION
BROWNING - FERRIS GAS SERVICES, INC.
G-21
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LANDFILL GAS BLOWERS
The centrifugal blower system acts as the driving force to transfer the landfill gas from the wells
through the piping network and into the enclosed flare system for subsequent combustion. The
blower system has two parallel blowers which are alternated on a weekly basis to provide 100%
backup should the operating blower fail. In blower stations requiring two or more blowers
operating together, at least one spare blower is always installed.
BLOWER SIZING
The blower must have the capacity to transfer the produced landfill gas from the extraction wells
to the enclosed flare for combustion. The required size of the blower is determined by the total
head loss (measured in inches of water column) generated from the friction encountered1 to
remove and transfer the gas through the piping network and into the enclosed flare system. The
blower is sized so that an 18 inch water column pressure is maintained at the outlet, while the
suction pressure varies according to design.
BLOWER CONSTRUCTION
The blower specified for the most landfills will be a centrifugal type blower. The advantages
and specific design features of this type of blower are listed below:
• Constant efficiency; little wearing of internal pans; ample clearance throughout the
blower.
• Centrifugal blowers can be direct driven or belt design requirements and flexibility
needed.
• Since the centrifugal blowers all have outboard mounted bearings, no chance exists for
lubricant to contaminate the air stream.
•
• Variable volume at constant speed. Power requirements vary directly with gas volume
requirement. No special bleed off devices are needed.
• Relatively constant pressure at constant speed.
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FIGURE 13
NOTE:
o
Ko
CO
MOUNT OUTLET PIPE AS CLOSE TO
CEILING AS POSSIBLE.
HOPE PIPE
P»BTICUI»TE FILTER
REGULATOR
PNtUMAllCAl I 1 OPLIUItn
FAIL-CLOSED VALVE
COMPRESSOR INTME
10 BE LOCATED
OUTSIDE OF BUILDING
GALVANIZED i |
PIPE AND FIT TINGS I I
HOPE PIPE TO
CONDENStlE PUMPS
38* MINIMUM BURIAL
OF Alf) LINE
BLOWER BUILDING SKID - ELEVATION VIEW
BROWNING - FERRIS GAS SERVICES, INC.
-------
Centrifugal blowers produce unusually low noise; silencers are usually not required.
Relatively lightweight; no special foundation is required.
Centrifugal blowers produce a smooth non-pulsating air flow when operating at any point
beyond the surge limit.
Since horsepower is in direct proportion to the volumetric demand, an ammeter can be
calibrated in CFM to indicate gas flow when required.
Inlet and outlet heads and interlocking intermediate sections with integral annular
diffusers are made from high quality cast iron. Heads are provided with mounting legs
and tie-rod lugs. Steel tie-rods bind entire housing into solid integral unit. Inlet head
includes diffuser to direct air to inlet of first impeller. Outlet head is of vortex design to
eliminate friction.
Impellers are cast aluminum alloy, smooth finish, shrouded-type securely keyed to the
shaft and held in place by lockwashers and locknuts. Impeller hubs butt against each
other. Ample clearance throughout the interior of the machine prevents wear and
maintenance problems, eliminates the need for lubrication.
Each impeller is precisely balanced, assuring smooth operation and freedom from
destructive vibration.
Non-sparking aluminum or bronze labyrinth seals at the housing prevent gas losses
between shaft and casing.
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LANDFILL GAS SYSTEM OPERATION
Landfill gas, a mixture of primarily methane and carbon dioxide, is generated as a by-product
of the anaerobic decomposition of refuse. This gas generation results in a positive pressure under
the landfill cap and forces the gas through the surrounding soils or other paths to a point where
the pressure is relieved. To mitigate the problems associated with this migrating.gas, a landfill
gas extraction system is installed at the landfill. This extraction system will operate by changing
the pressure within the landfill to a vacuum.
Extracted landfill gas will be destroyed by combustion in the proposed enclosed flare. The
landfill gas extraction system will be equipped with two centrifugal fans (blowers) to provide a
source of vacuum to pull methane from the landfill. Because only one blower will operate at any
given time, this redundant capacity provides for continuous system operation at times of
scheduled maintenance or mechanical failure.
OPERATION
Operation of the Landfill Gas Extraction System consists mainly of regulating and adjusting the
amount of vacuum available at each extraction well through the use of valves. This adjustment
of vacuum, and therefore flowrate, is referred to as "balancing" the gas system. A balanced
system is one in which each well is adjusted to extract the maximum amount of gas possible
without causing air to be pulled through the landfill cover and into the extraction system. Some
of the tests performed to balance and insure the efficient operation of the gas system are:
1) Flowrate Into The Flare
2) Percentage Methane Into The Flare
3) Gas Temperature At The K.O. Pot
4) Percentage Methane At Each Well
5) Vacuum At Each Well
6) Gas Temperature At Each Well
7) Flowrate At Each Well
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WELLS
Because methane production in the landfill is dependent upon many factors, the amount of
vacuum required to extract the gas will vary at each well and also with time. Generally, a
vacuum of only 0.5 - 3.0 inches of water column is applied to the extraction wells along the
systems' perimeter. Experience has shown this to be adequate to control gas migration and that
greater vacuums result in excessive air intrusion due to the large area of exposed landfill cap
within the influence areas of these wells. Interior wells however, due to the relatively small area
of exposed cap, will usually have a vacuum in the range of 2-7 inches of water column applied.
In order to achieve and maintain a well balanced system, vacuum, gas concentration, and gas
temperature are measured weekly at each well. In addition to these weekly tests, flowrates are
periodically measured to help establish the correlation between vacuum and flowrate at each
individual well.
Because landfill gas is generated at a mixture of approximately 50% methane and 50% carbon
dioxide, methane concentrations of less than 45% are indicative of air intrusion through the
landfill cover. Conversely, high methane concentrations indicate that more landfill gas is being
generated than is being extracted by the well. Therefore, methane concentration is the primary
test used to determine if the flowrate should be increased or decreased.
Vacuum is measured to establish its' relationship with gas concentration and extraction rate at
each well. Records are kept of these relationships to aid in determining the optimal flowrate to
maximize gas extraction and minimize air intrusion at each well. Instantaneous vacuum readings
are used to correctly adjust the wellhead valve to the desired vacuum. Abnormal vacuum
readings are indicative of and are used to locate pipe blockages or restrictions due to pipe failure
or water blockage.
Temperature of the landfill gas is measured and recorded at each extraction well weekly to help
detect the onset of air intrusion with the corresponding possibility of spontaneous combustion
WRE92045
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within the landfill. Although temperatures will vary for each extraction well, it should remain
reasonably stable at a particular well. A sharp increase in flow temperature accompanied by a
decrease in methane concentration is indicative of air intrusion into the landfill.
LATERALS AND HEADERS
Due to the extremely corrosive conditions of the landfill environment, all underground laterals
and headers are to be constructed of SDR 17 High Density Polyethylene (HDPE). HDPE is
extremely resistant to the corrosive nature of the landfill gas and condensate. Also, because of
its' flexibility and durability, HDPE is well suited to withstand the stresses imposed by
differential settlement within the landfill.
Valves are located at several points in the header pipe to isolate small areas of the system when
maintenance, repairs, or new construction is required. This allows the other portions of the
system to continue to operate as normal, thereby minimizing system downtime.
Condensate sumps, located in the low spots of the Header pipe, are designed to collect and hold
any gas condensate that may be generated by the cooling gas as it travels through the pipeline.
These sumps are pumped dry as required to keep the headers and laterals from becoming filled
with condensate and preventing the free flow of gas. Normally, each sump will be pumped dry
every week, or automatically pumped to a central storage tank or sewer system.
BLOWERS AND FLARE EQUIPMENT
A knockout pot (sometimes referred to as a scrubber) is simply an expansion chamber located
just upstream of the blowers. As gas flows through the pot, the decrease in pressure and the
subsequent cooling of the gas allows any remaining liquids to drop out of suspension. A sight
glass, located on the pot, indicates when the liquid from the pot must be drained.
Operation of the blowers is in accordance with the manufacturers recommended procedures and
is controlled by switches on the flare control panel and valves located next to each machine.
WRE92045
G-27
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Blowers are alternated weekly to allow time for routine maintenance and to insure that each
blower is in working order.
Operation of the flare station is in accordance with the manufacturers recommended practices.
Normally the flare will be operated in the "automatic" mode which provides for a safe automatic
shutdown and restart if a problem is detected. Temperature is controlled on the flare by adjusting
the amount of air that is allowed into the flare.
WRE92045
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APPENDIX H: SELECTING ELECTRICAL GENERATING EQUIPMENT FOR USE WITH
LANDFILL GAS (Paper)
Charles E. Anderson
Manager Landfill Gas Recovery Department
Rust Environment & Infrastructure—Solid Waste Division
In Proceedings of the SWANA 16th Annual Landfill Gas Symposium.
SWANA. Louisville, Kentucky. March, 1993.
H-1
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CHARLES E. ANDERSON, PE
MANAGER, LANDFILL GAS RECOVERY DEPARTMENT
RUST ENVIRONMENT & INFRASTRUCTURE - SOLID WASTE DIVISION
Introduction
In this paper the author will discuss the attributes of various
technologies for generating electricity while utilizing landfill
gas as a fuel. The'author will concentrate only on proven
technologies with significant numbers of installations currently
in service. Comparisons between the technologies will be made in
the categories of eguipment size, installation and operating
cost_s,. air emissions, and plant efficiency. The paper'will
conclude by summarizing the advantages and disadvantages of each
technology.
Technologies Currently Being Utilized
There are currently three basic technologies commonly utilized in
the production of electric power from landfill gas. These
technologies are steam turbines, combustion gas turbines, and
internal combustion reciprocating engines. According to a recent
survey conducted by the the United States Environmental
Protection Agency (US EPA) , there were 85 landfill
gas-to-electrical generating plants operating across the nation
during 1992 (Thorneloe, 1992). As indicated in Figure #1,
approximately 4% of the plants utilized steam turbines, while 25%
utilized combustion gas turbines and 71% utilized internal
combustion reciprocating engines. None of the electrical
generating projects were purported to utilize some other form of
technology.
The selection of a particular technology is usually predicated
upon the size of the project, the relative economics of the
various technology alternatives, permitting constraints, and site
specific operational considerations. According to statistics
compiled by Governmental Advisory Associates, Inc., the power
output ratings of operating landfill gas-to-electric plants
ranged from 70 kilowatts (KW) to 47,000 KW. The mean output
H-2
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rating of all plants was 4,053 KW (Berenyi & Gould, 1991).
Figure #2 depicts the number of landfill gas-to-electric plants
in each power output size.
Ecruipment Sizes and Operational Considerations
In developing landfill gas to electrical generation projects, it
is vital to match the equipment fuel requirements with the
quantity of available landfill gas over the life of the project.
All three of the technologies examined in this paper operate most
efficiently at full load. In addition, since the majority of the
costs associated with a landfill gas plant are often fixed (e.g.,
financing, labor, etc.) while the majority of the revenue stream
is variable (e.g., based upon kilowatt-hour power sales), the
selection of equipment size and the staging of equipment is
critical to financial success.
Commercially available steam turbines range in size from
approximately 100 KW to over 1,000,000 KW. Steam turbines
suitable for utilization in landfill gas projects may be either
condensing (i.e., exhaust steam below atmospheric pressure) or
non-condensing (i.e., exhaust steam above atmospheric pressure).
Figure #3 depicts a typical condensing steam turbine plant.
The steam turbines themselves require no special modification for
use in a landfill gas project. However, the boilers used to burn
the landfill gas and generate the steam must have burners
designed to handle low BTU gas and tubes designed to withstand
the acids formed from the hydrogen sulfide and halogen compounds
found in the gas. Steam turbine plants do have three operational
considerations worth noting. First, the steam cycle requires a
relatively copious clean water supply, since water is continually
lost through boiler blowdown and cooling tower evaporation.
Boiler feed water cleanliness is vital to long term plant thermal
efficiency, so operational costs increase as water purity
decreases. Second, codes in many areas of the country require
that a licensed operator man the facility whenever the boiler is
in operation. These codes are a throwback to the days when
automation did not exist and boiler explosions were common.
Finally, steam turbine boilers can readily accommodate
significant variations in the BTU value and composition of
landfill gas without major adjustments to the combustion control
system.
The majority of the combustion gas turbines operating on landfill
gas are simple cycle single shaft machines, although some
recuperated machines are in service. The sizes of commercially
available combustion gas turbines for natural gas service range
from less than 1,000 KW to over 100,000 KW. The most commonly
used machine for landfill gas service is the Solar Centaur T4500
H-3
-------
turbine/genera tor set, which is nominally rated at 3,300 KW.
Figure #4 depicts a typical simple cycle combustion gas turbine
plant.
The Solar Centaur landfill gas turbine is almost identical to a
natural gas fired unit,, except for fuel system modifications.
Due to the low BTU value of landfill gas, the turbine fuel train
has been doubled to include twice the number of fuel control and
regulating valves, as well as twice the number of fuel injectors.
Since air is used for cooling as well as combustion, the majority
of the power from the expanding gasses in the turbine section is
utilized to compressor air. High gas pressures, and hence a
sophisticated fuel gas compressor skid, are required to inject
fuel gas into the combustor.
Landfill gas fueled Solar Centaur turbines operate nearly as well
as natural gas fired units, but with three nuances. First,
silica deposits form on the turbine blades and nozzles of the
landfill gas units, and abnormally high tip-shoe rub is
experienced. The formation of the silica deposits is obviously
related to the composition of the landfill gas, but the exact
mechanism of formation is not understood. Second, the landfill
gas fired units are capable of producing approximately 15% more
power than a natural gas unit. This is due to the fact that the
carbon dioxide (CO ) in the landfill gas cools the combustion
temperature and allows more fuel BTU input, and hence more power
output, before the turbine blades reach critical temperature.
Finally, the low BTU value of the gas can make ignition difficult
during start-ups and cause flame-outs when load is dropped
rapidly.
Internal combustion reciprocating engine technology provides the
broadest range of design variations. Commercially available gas
fueled, spark ignited engine ratings range in size from less than
100 KW to more than 10,000 KW. Caterpillar, Cooper-Superior, and
WauJcesha all have more than 20 engines operating on landfill gas
(Augenstein & Pacey, 1992). Figure #5 depicts a typical landfill
gas-to-electrical generating plant employing internal combustion
reciprocating engines.
Reciprocating engines in landfill gas service can be subdivided
into categories, based upon the design characteristics of their
carburization systems and their operating speeds. The first
category is the naturally aspirated (NA) engine, which commonly
ranges in size from less than 100 KW up to approximately 1,000
KW. The NA engine draws the combustion air/landfill gas fuel
mixture into the carburetor from atmospheric pressure and in
stoichiometric proportions. The advantage of this air/fuel
carburization system is that it is relatively simple and robust
in handling the contaminants found in landfill gas. The fuel gas
compressor can be simple, since low fuel pressure is required.
The disadvantage of this type of engine is its high capital cost
H-4
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to power output ratio (i.e., $/KW). In addition, the emissions
of nitrous oxides (Npx) and carbon monoxide (CO) are relatively
high and greatly' variable based upon operating conditions and
mechanical adjustments.
The second category of engine is "lean burn", which means that
air in excess of stoichiometric requirements is introduced into
the combustion chamber. Typically, lean burn engines are
turbo-charged and aftercooled. This means that the exhaust
gasses from the engine are used to boost the pressure of the
incoming combustion air, which is then cooled before being fed
into the carburization system. This "supercharges" the
combustion chamber with the air/fuel mixture and consequently
provides for increased engine power output. In engines having
normal spark plugs and a single chamber in the cylinder, air/fuel
mixtures can be leaned out to provide approximately 7% excess
oxygen in the exhaust gas stream. In engines provided with dual
combustion chambers, an easy to ignite air/fuel mixture is
introduced into the pre-combustion chamber and ignited by a spark
plug, while a very lean air/fuel mixture is introduced into the
main cylinder. This allows air/fuel mixtures to be leaned out to
provide approximately 11% excess oxygen in the exhaust gas
stream. The significance of excess oxygen will be discussed in
the air emissions portion of this paper.
Finally, reciprocating engines can be categorized based upon
their rotational speed or revolutions-per-minute (RPM) . Low
speed engines are defined to operate below 700 RPM, while medium
speed engines operate between 700 RPM and 1,000 RPM, and high
speed engines operate above 1,000 RPM. The slow speed engines
are normally large in physical size and power" output. A long
stroke and slow speed provides for the maximum conversion of
energy from fuel combustion to rotational motion. The slow speed
also reduces component wear, and thus minimizes maintenance
requirements. This category of engine strives for fuel
efficiency, low maintenance, and high reliability. The
disadvantages of these engines are their relatively large size
(both physical and power output), and their relatively high
capital cost to power output ratio ($/KW). Alternatively, high
speed engines typically have short strokes and attempt to
maximize power output while minimizing physical size. The high
speed increases component wear and maintenance requirements.
However, high speed engines have relatively low capital cost to
power output ratios ($/KW).
Probably the most common engine/generator used in landfill gas
service, the Caterpillar #G3516SITA-LE, is turbo-charged,
aftercooled, and operates at 1200 RPM. The #G3516SITA-LE is
rated at 800 KW output with 130 degree Fahrenheit aftercooler
water temperature. In comparison, the #G3516SINA naturally
aspirated version of this engine is only rated at 455 KW. The
#G3516SITA-LE engine strives for a low capital cost to power
H-5
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output ratio. The disadvantage of a turbocharged engine is that
the exhaust valves and turbo-chargex wheels are subject to
relatively high temperature gasses and the build-up of deposits
containing silica. The high operating speeds accelerate the wear
caused by these deposits. These factors require increased
maintenance, when compared to natural gas fueled units. In
addition, more sophisticated fuel gas compressor skids are
normally required to deliver landfill gas into the carburization
system at approximately 35 pounds per square inch gauge pressure
(PSIG) . Caterpillar has attempted to minimize the fuel gas
compressor concern by developing a carburization system which
mixes the gas and air before turbocharging, thereby reducing the
necessary fuel gas pressure to 2 PSIG.
It should be noted that all types of internal combustion
reciprocating engines are subject to corrosive attacks from the
halogen compounds found in landfill gas. The combustion of
landfill gas causes acids to form, which can make their way into
the lubricating oil and attack close tolerance metal surfaces
associated with the engine's top-end (e.g., valve stems, valve
guides, cams, etc.) and bearings. The most common methods of
combatting the corrosion are as follows:
1) Use lubricating oil containing a high "Total Base Number"
(TEN).
2) Use oil filters treated with chemicals to neutralize acids.
3) Plate components subject to attack with chrome or
manufacture from corrosion resistant metals.
4) Raise the operating temperature of the engine to maintain
acids in vapor state.
5) Draw a vacuum on the engine crankcase to evacuate acid
vapors before they can contaminate the lubricating oil.
Installation and Operating Costs
In comparing installation and operating costs for the three types
of technologies, it is difficult to obtain an unbiased analysis
for several reasons. First, there is the issue of economies of
scale. As with any electrical generating facility, the cost per
kilowatt of capacity declines as the power output rating
increases. Second, to perform an analysis, specific pieces of
equipment must be compared. Finally, the analysis must include
all necessary plant auxiliaries in addition to the prime movers
alone.
In an attempt to circumvent these problems, the author decided
H-6
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that the "theoretical" plant should be rated approximately 5,000
KW net output capacity. This size is in a range which all three
technologies can efficiently serve. Second, the author has
included the installation, operation, and maintenance costs
associated with the prime mover, building structure, electrical
interconnect, fuel gas compression equipment, and auxiliary
equipment in the analysis. Any costs associated with the '
financing, project development, gas collection system, site
specific work, or environmental permitting/compliance have been
excluded. Finally, the author decided to compare only the most
frequently utilized equipment from each technology. These are
condensing steam turbines, simple cycle combustion gas turbines,
and lean burn, turbo-charged, aftercooled, high speed internal
combustion reciprocating engines. Table #1 indicates the gross
and net power output ratings of the theoretical plants.
It is also important to address the issue of gas clean-up. As
previously noted, reciprocating engines are the most susceptible
of the three technologies to the effects of landfill gas
constituents. Economic trade-offs must be considered in
determining the level of gas processing to remove contaminants
and particulate. Cleaning up the gas reduces prime mover
maintenance, but adds both installation and operating costs. For
the purposes of the analysis, an attempt was made to level the
playing field by following the same basic philosophy of gas
clean-up, but taken to the level of sophistication required for
each technology. The basic design steps are as follows:
1) Liquid slug and large particle knock-out.
2) Compression to working pressure.
3) Gas cooling to ambient temperatures to condense water vapor.
if
4) Filtration of small particles and coalescing of liquid
droplets.
.5) Reheating above the gas dew point.
It should be noted that the boiler burners of a steam turbine
power system requires only steps 1 and 2 above, while the
combustion turbine and reciprocating engine power systems
normally require all of the steps listed above.
;Table #2 lists the construction costs for the three "theoretical
plants" on a dollars per net kilowatt basis, while Table #3 lists
the operation and maintenance costs on a dollars per net
kilowatt-hour basis. From this analysis it can be seen that
internal combustion reciprocating engine plants have the lowest
installation costs, at $894 per net KW, but also have the highest
operating costs, at approximately $0.013 per KWH. The combustion
gas turbine plants have the highest installation costs, at $1,20'2
H-7
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per net KW, but the lowest operating costs, at less than $0.010
per net KWH.. Steam turbine power systems are in the middle, with
$906 per net KW installation costs and slightly more than $0.010
per net KWH operating costs. In reviewing this data it is
important to recognize that site specific factors (e.g., quantity
of recoverable gas, availability and cost of water, waste water
and gas condensate disposal, etc.), financing costs, and air
permitting constraints have not been figured into the data. The
cost impact of these items could easily outweigh the underlying
advantages of the "least cost" technology.
Thermal Efficiencies
Landfill gas-to-electrical generation facilities acquire revenues
based upon the amount of energy sold (i.e., net plant KW output
multiplied by the hours of operation). Previous studies have
shown that landfill gas collection system problems account for
the majority of unplanned downtime and capacity shortfalls
experienced at gas-to-electric generation facilities. All three
technologies are capable of providing plant availabilities in
excess of 95% when only planned maintenance is considered
(Markham, 1992) . As a result, net power output, is tied directly
to the plant thermal efficiency, or thermal heat rate.
In theory, given-a fixed quantity of gas, a plant with a higher
thermal efficiency would provide a higher net power output, and
hence more revenue. In reality, however, incremental equipment
ratings readily available from the manufacturers' impose
constraints. Thus the most "economic" plant may have more or
less fuel consumption capability than the amount of recoverable
gas at any given time. 'Never the less, thermal efficiency is an
important consideration in selecting the technology to use on a
project, as well as selecting between equipment within a
technology category.
Figure #6"depicts both the prime mover and overall plant thermal
efficiencies for the theoretical plants with approximately 5,000
KW net output. The figure indicates that the internal combustion
reciprocating engine plant has the highest prime mover and plant
efficiencies (i.e., lowest heat rates) at 12,200 BTU/KWH and
13,140 BTU/KWH respectively. Combustion gas turbines follow with
14,800 BTU/KWH prime mover and 17,900 BTU/KWH plant heat.rates.
Steam turbines are the least efficient in this size range, with
20,800 BTU/KWH steam cycle and 23,540 BTU/KWH plant heat rates.
It should be noted that both steam turbine plant and combustion
gas turbine plant power output capacities will vary with ambient
temperature. In the case of the steam turbine plant, condenser
water temperature impacts the amount of steam which can be pushed
through the turbine. In the case of combustion turbines, excess
H-8
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air must be compressed and used to provide cooling to temperature
critical components. When ambient air temperatures increase, the
amount of work expended to compress the hotter and less dense air
increases. Consequently, the power'which can be obtained from
steam or combustion gas turbine plants decreases as ambient
temperature increases.
It is also vital to note equipment efficiency at partial loads.
In the case of reciprocating engines, prime mover thermal
efficiency decreases at a relatively constant rate from 28% at
full load down to approximately 21% at 25% load. In the case of
combustion gas turbines, prime mover efficiency decreases from
23% at full load down to only 13% at 25% load. The steam turbine
cycle thermal efficiencies drop off approximately 17% at full
load to 10% at 25% load. Thus, the internal combustion
reciprocating engine plant would provide an even greater
advantage in terms of thermal efficiency if the plant fuel
capacity exceeded the recoverable gas quantity. Since the
quantity of recoverable landfill gas will vary over the life of a
project, partial load efficiencies must be carefully considered
in the selection of the prime mover technology.
Air Emissions
The final area to be investigated is equipment air emissions.
With the enactment of the Clean Air Act, permitting and
compliance with air emissions' regulations will continue to
increase in importance. The criteria air pollutants which are of
concern for landfill gas recovery plants are nitrous oxides
(NOx), carbon monoxide (CO), non-methane organic compounds
(NMOC's), particulate matter (PM) , and sulfur oxides (SOx) . Once
again, in order to maintain a level playing field, comparison of
the technologies will be based upon the plant emission rate per
net KW output. Table #4 lists the annual emission levels for the
three technologies. The data has been extrapolated to correspond
to the theoretical plants under consideration from manufacturers7
information, US EPA reports, 78 combustion gas turbine emissions
tests, and 23 internal combustion reciprocating engine emissions
tests (US EPA, 1990).
The basic keys to NOx, CO, and NMOC emissions are combustion
temperature, air/fuel ratio, and residence time that the
combustion products are confined at elevated temperatures within
in the equipment. There are trade-offs inherent in trying to
control the emission level of a particular pollutant, since the
formation of other pollutants may be promoted.
Because there is very little fuel bound nitrogen in landfill gas,
NOx is formed when free nitrogen in the combustion air combines
with oxygen at high temperatures. High temperatures and long
H-9
-------
residence times promote the formation of NOx. As previously
stated, combustion gas turbines utilize large quantities of
excess air for cooling, thus providing approximately 15% excess
oxygen in the exhaust. The excess air and relatively short
residence time provide the combustion turbine plant with NOx
emissions of only 41 tons per year (TPY) . The boilers of
landfill gas fueled steam turbine power systems typically operate
between 1500 and 2000 degrees Fahrenheit and have combustion
controls which monitor excess oxygen in the exhaust to control
combustion efficiency. These factors, combined with relatively
short residence times, mean that the steam turbine plant NOx
emissions would be approximately 68 TPY. "Low emission" internal
combustion reciprocating engines typically operate with 7% or
greater excess oxygen in the exhaust, and the residence time in
the cylinder -and exhaust manifold typically exceeds the time
experienced in the other technologies. These factors combine to
give the reciprocating engine plant emissions of 184 TPY, or
three to four times higher NOx levels than the other two
technologies. It should be noted that slow speed, lean burn
engines can provide the better NOx emission levels than
represented by our theoretical reciprocating engine plant.
The factors promoting the formation of CO are opposite of those
for NOx, since CO is a product of incomplete combustion. Very
low combustion temperatures, rich air/fuel mixtures, or
incomplete mixing of the air and fuel tend to promote the
formation of CO. The boilers used in steam turbine plants
provide the best CO emission levels, at approximately 17 TPY.
The combustion gas turbine plant follows with CO emissions of 51
TPY. At 144 TPY for CO emissions, the internal combustion
reciprocating engine plant is again significantly higher than the
other technologies. If NOx levels are reduced in reciprocating
engines by changing the air/fuel mixture or spark timing, CO
levels are often increased. Thus there is a trade-off in the
control of these pollutants.
The destruction of non-methane organic compounds is enhanced by
high combustion temperatures and long residence times. If
operating properly, all three technologies can provide 98%
destruction efficiency or better. The results of the analysis
show that the steam turbine plant provides the lowest level of
NMOC emissions (i.e., highest level of destruction) at l TPY,
followed by the combustion turbine plant at 12 TPY, and by the
internal combustion reciprocating engine plant at 17 TPY.
Since landfill gas contains no "solids" other than soils carried
along due to velocity, particulate matter emissions are minimal.
The distinction between the three technologies is evident only
due to the combustion of lubricating oils used in the fuel gas
compressor or prime mover. Consequently, it is not surprising to
find that the steam turbine plant provides the lowest PM
emissions at l TPY, followed by the combustion gas turbine plant
H-10
-------
at 2 TPY, and the internal combustion reciprocating engine plant
at 3 TPY.
Sulfur oxide concentrations in the exhaust gas will be directly
proportional to the sulfur bearing compounds (e.g., hydrogen
sulfide, mercaptans, etc.) found in the landfill fuel gas. Since
these sulfur bearing compounds are converted directly to SOx, the
choice of technology will not materially impact plant emissions
for a given volume of landfill gas. However, since the
theoretical plants have differing heat rates, they will emit
different levels of SOx at full load. Given "typical" landfill
gas composition, the steam turbine plant would emit approximately
38 TPY of SOx, while the more efficient combustion turbine plant
would emit 30 TPY, and most efficient internal combustion
reciprocating engine plant would emit only 21 TPY.
The analysis reveals that steam turbine power plant provides the
lowest overall emission levels, followed in order by the
combustion gas turbine plant and the internal combustion
reciprocating engine plant. It is important to note that all
equipment manufacturers are making strides in reducing emission
levels. In addition, exhaust gas clean-up equipment may be
applied to all three technologies to further reduce emission
levels. When investigating emission reduction systems, the
project developer must consider more than the installation and
operation costs of such systems. The trace components found in
landfill gas can react with system chemicals and catalysts to
reduce the effectiveness of the systems (Augenstein & Pacey,
1992). The underlying advantages and disadvantages of the three
technologies should consequently be the primary focus when
considering air emissions.
Conclusion
In summary, it can be seen that steam turbines, combustion gas
turbines, and internal combustion reciprocating engines each have
inherent strengths and weaknesses. Tables #5, #6, and #7 list
the inherent advantages and disadvantages of each technology.
The relative importance of installation and operation costs, heat
rates, and air emissions must be taken into consideration when
selecting prime movers for utilization in landfill gas-to-
electrical generation facilities. It must be remembered,
however, that impact of site specific considerations can be more
important to development of a successful project than the
underlying characteristics of the technology chosen.
H-11
-------
FIGURE #2
LANDFILL GAS-TO-ELECTRICAL GENERATION PLANTS
SIZES IN OPERATION IN THE U.S. DURING 1992
FIGURE #1
LANDFILL GAS-TO-ELECTRICAL GENERATION PLANTS
TYPES IN OPERATION IN THE U.S. DURING 1992
7 0
60
I
CO
STEAM
TURBINES
4%
COMBUSTION
GAS
TURBINES
25%
INTERNAL COMBUSTION
RECIPROCATING ENGINES
30
66
5,000 TO
10,000 KH
10,000 TO OVER
15,000 KW 15,000 KW
SIZE OF PLANT
-------
FIGURE #3
CONDENSING STEAM TURBINE
LANDFILL GAS-TO-ELECTRICAL GENERATION PLANT
INLET
AIR I F.D. FAN
INLET
KNOCKOUT
EXHAUST
GAS
* SLOWDOWN
w
*-
'"S *"
z) '
BOILER
4
STEAM
TURBINE
GAS I
COMPRESSOR
LANDFILL
GAS
GENERATOR
CONDENSER
I
COOLING
TOWER
t
CONDENSATE
PUMP
COOLING
WATER PUMP
'MAKE-UP
WATER
DEAERATOR
T
BOILER FEED PUMP
H-13
-------
FIGURE #4
COMBUSTION GAS TURBINE
LANDFILL GAS-TO-ELECTRICAL GENERATION PLANT
INLET
KNOCKOUT
GAS RECYCLE
VALVE
LANDFILL
GAS
1ST STAGE GAS
COMPRESSOR
INTERSTAGE
KNOCKOUT
CONDENSATE
FINAL
FILTER
-
AIR
INLET
AIR
FILTER
EXHAUST
EXPANSION
TURBINE
COMBUSTOR
COMPRESSOR
SECTION
H-14
-------
FIGURE #5
INTERNAL COMBUSTION RECIPROCATING ENGINE
LANDFILL GAS-TO-ELECTRICAL GENERATION PLANT
INLET
KNOCKOUT
LANDFILL
GAS
CONDENSATE
GAS RECYCLE
VALVE
FUEL GAS
COMPRESSOR
"
AIR
INLET
AIR
FILTER
GENERATOR
EXHAUST
RECIPROCATING
ENGINE
AFTERCOOLER
WATER
ILfi
JACKET WATER
RADIATOR
H-15
-------
FIGURE #6
LANDFILL GAS-TO-ELECTRICAL GENERATION PLANTS
THERMAL EFFICIENCIES
PRIME MOVER
'EFFICIENCY
TOTAL PLANT
'EFFICIENCY
30%
25%
20%
15%
10%
5%
20,800
BTD/KWH
23,540
BTU/KHH
14,800
BTU/KWH
STEAM
TURBINE
,940
JTU/KWH
COMBUSTION
GAS TURBINE
TYPE OF PLANT
12,200
BTU/KWH
,13,140
BTU/KWH
I.C. RECIP
ENGINE
H-16
-------
TABLE #1
LANDFILL GAS-TO-ELECTRIC PLANT
POWER OUTPUT RATINGS
m^mmmm
PRIME MOVER
NO. OF UNITS
GROSS PLANT RATING
AVERAGE LOAD
PERCENT OF CAPACITY
NET PLANT RATING
STEAM TURBINE
6,000 KW
1
6,000 KW
700 KW
11.7%
5,300 KW
COMBUSTION TURBINE
3,150 KW
2
6,300 KW
1,100 KW
17.5%
5,200 KW
1C RECIP. ENGINE
800 KW
7
5,600 KW
400 KW
7.1%
5,200 KW
-------
TABLE #2
LANDFILL GAS-TO-ELECTRIC PLANT
CONSTRUCTION COSTS
ITEM
UTILITY INTERCONNECT
BUILDING & FOUNDATIONS
ELECTRICAL EQUIPMENT
& CONTROLS
PRIME MOVERS
FUEL GAS COMPRESSORS
BOILER, CONDENSER,
& COOLING TOWER
ENGINEERING
TOTAL COST
COST PER GROSS KW
COST PER NET KW
STEAM TURBINE
250,
500,
350,
1,500,
100,
1,900,
200,
$4,800,
000
000
000
000
000
000
000
000
$800
$906
COMBUSTION TURBINE
250,000
400,000
400,000
3,500,000
1,500,000
0
200,000
$6,250,000
$992
$1 ,202
1C RECIP. ENGINE
250,000
500,000
450,000
2,800,000
450,000
0
200,000
$4,650,000
$830
$894
I
I
oo
NOTE: Does not Include site specific or project development costs.
-------
TABLE #3
LANDFILL GAS-TO-ELECTRIC PLANT
OPERATION & MAINTENANCE COSTS
ITEM
LABOR
(Employee & Outside)
CONSUMABLES
(Oil, Chemicals, etc)
EQUIPMENT PARTS
& REPAIRS
MAJOR OVERHAULS
BUILDING MAINTENANCE
TOTAL COST
ANTICIPATED ON-LINE TIME
COST PER NET KWH
STEAM TURBINE
200
30
50
130
25
$435
$0.
,000
,000
,000
,000
,000
,000
90%
0104
COMBUST
160
25
90
110
25
. $410
$0.
ION TURBINE
,000
,000
,000
,000
,000
,000
93%
0097
ic RECIP. ENGINE;
180
100
120
117
25
$542
$0.
,000
,000
,000
,000
,000
,000
92%
0129
CO
NOTE: Does not include site specific or financing costs.
-------
TABLE #4
LANDFILL GAS-TO-ELECTRIC PLANT
AIR EMISSIONS
CRITERIA POLLUTANT
NOx
CO
NMOC
PM
SOx *
AIR
STEAM TURBINE
68
17
1
1
38
EMISSIONS (TONS/YEAR)
COMBUSTION TURBINE
41
51
12
2.
30
1C RECIP. ENGINE
184
144
17
3
21
I
I
O
NOTE: * - SOx emissions are based upon average tested levels of sulfur compounds found In landfill gas.
-------
TABLE #5
STEAM TURBINE
LANDFILL GAS-TO-ELECTRIC PLANT
ADVANTAGES
CORROSIVE IMPACTS OF GAS ARE MINIMIZED
CAPABLE OF HANDLING WIDE VARIATIONS IN GAS COMPOSITION
NO GAS CONDENSATE FORMED IN PROCESS
LOW AIR EMISSION LEVELS OVERALL
DISADVANTAGES
* i
REQUIRES CLEAN WATER SUPPLY j
TABLE #6
COMBUSTION GAS TURBINE
LANDFILL GAS-TO-ELECTRIC PLANT
OPERATING COSTS SENSITIVE TO WATER:
PORCHASE PRICE
PURITY
DISPOSAL COST
CODES' MAY REQUIRE 24 EOOR A DAY STAFFING
i.
INEFFICIENT AT SIZES LESS THAN 10,000 KW |
I
INEFFICIENT AT PARTIAL LOADS ' ' '
ADVANTAGES
SHALL PHYSICAL SIZE
LOW OPERATION AND MAINTENANCE COSTS
LOW NOx AIR EMISSIONS
DISADVANTAGES
HIGH CAPITAL COSTS
HIGH FDEL PRESSURE REQUIRED:
.HIGH PARASITIC LOADS
LARGE AMOUNTS OF GAS CONDENSATE FORMED IN PROCESS
SPECIALIZED TROUBLESHOOTING KNOWLEDGE REQUIRED
INEFFICIENT AT PARTIAL LOADS _.. ..
H-21
-------
TABLE #7
INTERNAL COMBUSTION RECIPROCATING ENGINE
LANDFILL GAS-TO-ELECTRIC PLANT
ADVANTAGES
BROAD RANGE IN ODTPDT RATINGS
COMMONLY DSHD TECHNOLOGY - MECHANICS AVAILABLE
LOW CAPITAL COSTS
EFFICIENT AT FULL LOAD AND PARTIAL LOADS
DISADVANTAGES
SUSCEPTIBLE TO CORROSION FROM HALOGEN COMPOUNDS
SENSITIVE TO CHANGES IN GAS COMPOSITION
HIGH OPERATION & MAINTENANCE COSTS:
OIL CHANGES
TOP END OVERHAULS
HIGH AIR EMISSION LEVELS OVERALL
BIBLIOGRAPHY
Augenstein, D. and J. Pacey. Landfill Gas Energy Utilization:
Technology Options and Case Studies. U.S. EPA /AEERL, Research Triangle
Park, NC. EPA-600/R-92-116 (NTIS PB92-203116). June 1992.
Berenyi, E. and R. Gould. 1991-92 Methane Recovery from Landfill
Yearbook. Governmental Advisory Associates, Inc. New York. 1991. pp
23.
Markham, M.A. Landfill Gas Recovery to Electric Energy Equipment:
Waste Management's 1991 Performance Record. Proceedings of the 15th
Annual Landfill Gas Symposium. SWANA, Silver Spring, MD. March 1992.
Thorneloe, S. A. Landfill Gas Utilization—Options, Benefits, and
Barriers. Presented at the 2nd U.S. Conference on Municipal Solid Waste
Management, Arlington, VA. June 1992.
U.S. Environmental Protection Agency. AIRS Facility Subsystem Source
Classification Codes and Emission Factor Listing for Criteria
Pollutants. EPA-450/4-90-003 (NTIS PB90-207242). U.S. EPA/OAQPS,
Research Triangle Park, NC. March 1990.
H-22
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APPENDIX I: GAS CONDITIONING KEY TO SUCCESS IN TURBINE COMBUSTION SYSTEMS
USING LANDFILL GAS FUELS (Paper)
Marty Schlotthauer
Senior Process Engineer, Technical Programs
Waste Management of North America, Inc.
Oak Brook, Ilinois
In Proceedings of the GRCDA/SWANA 14th Annual Landfill Gas Symposium.
SWANA. Silver Spring, Maryland.
1-1
-------
GAS CONDITIONING KEY TO SUCCESS
IN TURBINE COMBUSTION SYSTEMS
USING LANDFILL GAS FUELS
Marty Schlotthauer
Senior Process Engineer, Technical Programs
Waste Management of North America, Inc.
Oak Brook, Illinois
BACKGROUND
Waste Management of North America (WMNA) started generating electrical power in
December, 1985 from their landfill gas to electric facility at Omega Hills Landfill in
Germantown, Wisconsin. Initially two Turbine/Generator (T/G) systems were installed. Each
system consisted of a Hall Fuel Gas Compressor (FGC) skid and a Solar Centaur
turbine/generator set.
On August 15, 1988 after 20,935 operating hours, turbine #1 failed when a hole burned through
the combustor liner and housing. The plant operator actually observed a fire ball coming out
of unit #1 and immediately shut down the system. Turbine #2 with 20,562 operating hours had
exhibited a deterioration in performance over the previous several months. The unit #2 turbine
was also shut down and shipped along with unit #1 to the turbine manufacturer for a
comprehensive examination and failure analysis.
Unit #1: The combustor case exhibited a large protuberance with a central region which had
melted adjacent to an injector inlet. The combustor liner was also thermally distressed with
remnants of a small molten region on the cooling air louver near another injector boss. A fine
powdery red deposit covered all internal areas of the combustor. Examination of air blast tubes
showed that ajl fuel injectors and air blast tubes were constricted to some degree with a hard
black deposit.
1-2
-------
Chemical analyses of both the black deposit found in the blast tubes and the red surface deposits
found on the turbine blades were performed. The composition of the black deposit was mainly
carbon with small amounts of aluminum, iron, sulfur, magnesium, and silicon being detected
(see Table 1). The red deposit was mainly silicon, typical of deposits routinely found in turbines
operating in landfill gas application (see Table 2). Metallurgical and structure analysis
confirmed that all turbine components were designed and made to withstand the normal operating
condition. The problem, however, was due to blockage of the aforementioned extended air blast
tube. This blockage forced the fuel to pass and ignite between the liner and the case. The high
temperature of combustion caused the combustor case to melt.
Unit #2: Three of the first stage turbine blades had failures of varying degree in the blade
airfoils. All turbine section gas path components were found to have a heavy coating of a red
deposit. The combustor liner air blast tubes were partially blocked with a hard black deposit,
similar to turbine #1. Chemical analysis of the red deposit (see Table 2) revealed the presence
of oxygen (in the form of oxides), silicon, iron, sulfur, tin, calcium, and aluminum, very similar
to #1 turbine. Damage and deterioration of a combustion liner cooling air louver located
downstream of the injector blast tubes was also observed.
Metallographic examination provided sufficient evidence to conclude that thermal stress rupture
was the primary cause of blade failure. Similar to Unit #1, the deposit of oil and condensate
not only caused severe fuel mal-distribution but also interfered with the combustor aerodynamics
resulting in abnormal combustor exit temperature profile.
Further build up of the deposits caused the pressure inside the blast tube to exceed the combustor
inlet air pressure resulting in leakage of the fuel/air mixture outside the combustor can and
combustor housing.
The turbine manufacturer strongly recommended that fuel gas compressor oil and condensate
carryover be prevented from entering the engine fuel and combustion system. They also
recommended routine horoscope inspections of the injector and injector boss air blast tubes be
performed every 1000 hours.
1-3
-------
PROCESS DESIGN EVALUATION
Based on the turbine manufacturer's failure analysis and WMNA's own investigation it was
agreed that the problem had been initiated by the inlet gas and not the turbines themselves. To
thoroughly understand and resolve the oil carryover problem, WMNA conducted the following
evaluations of the process system as it was configured at the time of the failure. Refer to Figure
No. 1.
• Existing Filter/Separator (Fil/Sep) performance.
• Pipe route from the fuel gas compressor to the turbine/generator.
• Temperature and pressure differential profiles.
• Oil carryover quantities.
• Requirements for final filter/separator at the turbine inlet.
• Gas mixing versus gas to gas heat exchanger.
• Compressor operations and design.
• Effects of high ambient temperatures and high humidity on gas conditioning and turbine
performance.
1. Existing Filter/Separator Performance
The existing filter/separator was removing particles 1 micron in diameter and larger. It
was not designed nor rated to remove oil in the form of aerosols. The Fil/Sep unit
would however prevent slugs of oil or condensate from entering the fuel system when
properly installed and maintained. After consulting with major filter/separator
manufacturers, WMNA concluded that improved filtration was required at the T/G inlet.
The following design objectives were established as minimum requirements for the new
system.
Place a final filter as close to the turbine inlet as possible to remove oil droplets
and aerosols from the gas.
Use a two stage, reverse flow, inside to outside filter element system.
1-4
-------
Increase gas temperature above the dew point (after interstage cooling) so that oil,
water and emulsion can separate at the FGC skid.
Based on technical and cost analysis, a Pall Process Filtration Company Liquid/Gas (LG)
coalescer filter unit was selected. Pall guaranteed removal of 99.98% of solid and liquid
aerosols at 0.3 microns and above, with downstream concentration of 0.003 ppmw or
less.
2. Pipe Route From the FGC to the T/G
The existing piping was routed underground between the FGC and T/G skids.
Engineering calculation showed that the average heat loss underground (and to the above
ground portion) was approximately 66,000 btu/hr. On cold windy and/or rainy days this
heat loss would exceed 70,000 btu/hr. Because the gas leaving the FGC skid was at or
near its dew point, any cooling between the FGC and the T/G would result in formation
of condensation in the piping in substantial qnaitities. WMNA determined that low
points, fittings, and changes in direction should be minimized. A new pipe with proper
insulation was installed (see Figure 1).
3. Temperature and Pressure Differentials
The Chem Share ™ process simulator was used to evaluate the effects of temperature and
pressure on the gas under normal operating conditions. The process scheme was
simulated and dew point temperatures for inlet and outlet gas streams were calculated.
The existing operating configuration mixed hot gas from the third stage compressor
discharge bottle with cool gas directly from the air exchanger.
The system was set up to maintain a gas temperature of 150°F at the FGC skid before
the gas went to the turbine building. By mixing hot gas with cool gas before any
separation of free liquid from the cool gas, the product gas would have a dew point of
144°F. By the time the gas reached the turbine its temperature would drop to 130°F
1-5
-------
which was below the dew point temperature. Liquids would drop out between the FGC
and T/G setting up the possibility of slugging the filter at the turbine inlet.
This predictable situation was verified by the amount of liquids which accumulated at the
filter/separator (Fil/Sep) during normal operations. At times the levels in the upper
section of the Fil/Sep would fill unexpectedly, which indicated a slug of liquid had been
carried over to the filter by the gas. The system was not effective in reducing
condensation within the pipe between the FGC and T/G.
A solution to control the dew point and a means of maintaining some superheat between
the FGC and T/G was provided by a gas to gas heat exchanger installed between the final
separator and the T/G on the FGC skid. The hot gas from the third stage compression
at 275 °F was used to reheat the cool gas after it had been cooled and separation of
entrained oil and water was accomplished. The reheat, (via shell and' tube heat
exchanger) would raise final gas temperature by 20-30 °F and would insure that no water
condensed between the FGC discharge and the T/G inlet filter.
4. Oil Carryover Quantities
Each compressor used 1.1 to 1.5 gallons of lube oil per day. The existing Fil/Sep
removed 25% to 50% of the contaminants depending on ambient conditions. The amount
of suspended aerosols passing through the Fil/Sep and entering the turbine #1 was 2
ppmw which was equivalent to 110 pounds of oil a year; or 14.65 gallons per year.
5. Filter/Separatoribr the FGC
Since the gas entering the third stage discharge scrubber was above its dew point, the
scrubber was not removing any liquid. Sizing calculations also indicated that the existing
separator bottle was too small to effectively remove condensed liquids that were formed
in the aftercooler section. The Fil/Sep was adequately sized and was surplus equipment.
1-6
-------
It was decided to relocate the existing Fil/Sep to downstream of the aftercooler (see
Figure 1) as a pre-filter to the final liquid/gas coalescer.
6. Gas Mixing Versus Gas to Gas Exchanger
Gas properties and Chem Share results indicated that reheating the gas after the Fil/Sep,
by gas injection was not appropriate. Instead, we concluded that a gas to gas heat
exchanger (see Figure 2) would be quite efficient.
7. Compressor Operations and Design
The fuel gas compressor (FGC) had experienced valve plugging, emulsion formation and
piston failure, mostly due to poor pre-filtration. More efficient filtration was
recommended.
8. High Temperature and Humidity
High temperature and humidity experienced during the summertime could contribute to
instability of T/G operation due to changes in gas quality. Higher rates of condensation
along with poor liquid removal efficiency needed to be corrected to protect the T/G. A
gas to gas heat exchanger and improved filtration would control the dew point and
minimize the adverse effect of high temperature and humidity on the turbine
performance.
Selection of Pall Filtrations System Liquid Gas (LG) Coalescer/Filter
The Pall LG's were selected based on ability to remove both particulate and oil vapor
from the gas stream. The filters are located adjacent to the turbines with a minimum
amount of piping between the filter and the turbine fuel inlet flange. Pall filter housings
and dements were selected competitively based on removal efficiency of particulate and
1-7
-------
aerosols, as well as price and filter life expectancy. Performance guarantees of the Pall
system included the following:
1. Removal of 99.98% of aerosols and particulates 0.3 microns and larger with
downstream aerosol concentrations of less than 0.003 ppmw (3 parts per billion
by weight).
2. No re-entrainment of coalesced liquids.
3. Low saturated pressure drop (less than 1.2 psi differential).
4. Long filter life (typically 1 year or longer).
5. Filtration to remove both liquid and solid contaminants to the levels specified (in
the absolute terms).
POST-INSTALLATION REPORT
WMNA completed the above modifications during May of 1989. The first overall
inspection revealed the following:
After 90 days of operation the Pall LG performed efficiently and effectively. On July
11, and 12, the two turbine units were shutdown and boroscoped. The T/G fuel system
and the Pall filter housings were opened and inspected. The most significant evidence
of the effectiveness was seen in the fuel injector nozzles. They were exceptionally clean
and free of any buildup. There was no evidence of oil carryover and only slight
discoloration on the tips. The fuel control valves were dry and no residual oil or
condensate was found. The filter elements were clean and in "like new" condition. No
evidence of oil carryover was found downstream of the Pall housing. The horoscope
inspections showed no accumulation of oil or deposits on the blast tubes or turbine
combustor. The internals of the combustor and turbine inlet nozzles actually appeared
1-8
-------
to be cleaner, as if the engine was being cleaned by the cleaner fuel. An oil carryover
test was performed by Pall field services on July 26, 1989.
Results of the Pall field test are given in Table 3. The results confirmed that the Pall
LGs were performing to guarantee levels with paniculate removal (absolute) of 0.3
microns with aerosol penetration at 3 to 5 parts per billion. The Pall Well filter
cartridges were replaced after one year. The elements were not exhibiting any excessive
pressure drop and were replaced during routine maintenance. Inspection of the filter
elements was performed by removing a section; dissecting it and examining the internals.
The filters remained in excellent condition. Prior to installing the filters, fuel control
valves were rebuilt quarterly and oftentimes more frequently due to contamination and
condensation. No fuel valve rebuilds have been required since the filters were installed.
Ketema Gas/Gas Heat Exchanger
The gas to gas heat exchanger was installed to use third stage discharge gas at 250°F to
300 °F to reheat third stage filter/separator effluent to 30 °F above its saturated dew point
to eliminate the potential of condensation occurring between the fuel gas compressor and
the turbine inlet. Each exchanger was designed to handle 6300 Ib/hr of gas and exchange
91,000 btu/hr. The delta T approach temperature at design conditions was 30°F tube side
and 27 °F shell side. The heat exchangers were performing at or above the performance
specifications. During hot days and at reduced flow rates the exchangers provided delta
T approach in the range of 50°F on the shell and tube sides. This is due to higher third
stage discharge temperature and higher interstage cooling temperatures from the air
cooled exchanger. Gas leaving the FGC skid was a 170°F. Gas at the turbine inlet has
been between 145 °F and 160 8F during the summer season. During winter months
interstage temperatures decrease and TG inlets average 120°F. New exchangers are
more efficient because fouling factors which were considered in design have not
materialized. As fouling factors develop, efficiency and overall heat exchange rates will
be reduced to within the specified limits.
1-9
-------
Results
The gas/gas exchangers performed as specified. They provided a minimum of 30°F
reheat to maintain gas temperatures above the dew point at the turbine.
Post Installation Turbine Inspection
Since completion of the Process Modification Project and the start up of the units in mid-
May 1989, the results have been impressive. The purpose of the modifications was to
protect the turbine from oil carryover and to prevent future failures due to oil carryover.
The inspection of the turbine conducted on July 11 and 12, 1989, and January 1990
indicated the project had met or exceeded its objective in all respects. The horoscope
inspection was performed during the Omega Hills quarterly maintenance shutdown. The
fuel gas injectors were cleaner than any injectors inspected after 1200 hrs of operation.
The following turbine areas were also boroscoped and/or visually inspected:
Gas fuel manifold
Fuel injectors
Combustor liner and case
Turbine section 1st stage nozzles and blades.
The fuel manifold had a dark oil deposit in the upper section at the end plate baffle. The
volume of the oil deposit was similar to that observed in gas turbine fuel manifolds at
other sites. Due to their cleanliness, not all of the injectors were pulled from the
combustor section for inspection. The injectors had 1200 hours operating time since the
process modifications were introduced.
1-10
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Relocate Existing Filter/Separators
The existing filters were previously located at the turbine inlet where the Pall filters have
now been installed. The process review indicated that the existing separators for the final
stage after cooler effluent were undersized. Relocating the existing filters to the new
location provided more separation of condensate from the aftercooler as well as efficient
filtration of the gas upstream of the gas to gas heat exchangers. This change enabled the
gas/gas exchange to operate with exceptional efficiency. Fouling after 1 year has been
negligible.
Results
The existing (original) filters, which were relocated, provided efficient coalescing of
liquids entrained in the gas as it left the aftercooler section of the air cooler. Significant
quantities of water, oil and organics were removed from the system at this point. During
winter months when the aftercooler was most effective, the existing filters would remove
large quantities of liquids which would otherwise remain in the gas and wind up in the
piping and/or Pall LG Coalesces
Relocate Gas Piping Above Ground
Relocating the gas piping from below ground to above ground and insulating was
necessary to insure that the gas would remain above its dew point, and eliminate the
possibility of liquids accumulating in low spots in the system. Further inducement was
provided in that meter runs were required to measure the gas flow and provide samples
to the gas chromatographs for record keeping purposes. The below ground portion of the
line was a huge heat sink and reliable control of gas temperatures at the turbine was
impractical as long as the below ground lines were used. Two gas lines were installed
above ground, low points eliminated, meter runs with sample points installed, and
insulation provided to conserve heat.
1-11
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Eesulis
The temperature drop from the FGC to the turbine has been reduced from 30-60 PF down
to 15-20°F. The gas leaving the FGC final filter, had been as low as 110°F before the
modifications. The temperature at the turbine now ranges from 145 °F to 160°F
providing a margin of safety of 25°F to 40°F. During the winter season the margin will
narrow due to increased heat transfer in the air cooler, but the gas at the turbine will still
remain well above the dew point.
1-12
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PROJECT ECONOMIC ANALYSIS
Turbine failures are a very costly experience. Not only is the possibility of injury to operating
personnel extreme as a consequence of mechanical failure, but the repair costs are also very
high. The total cost to repair the failed turbines at Omega in 1989 was $477,000 including
freight and miscellaneous expenses to change out the railed units and install replacement units.
The cost breakdown is summarized below:
• Repair Cost Unit #1 $149,200
• Repair Cost Unit #2 $235,200
• Removal, package, freight
to turbine repair shop $8,650
• Freight, unpack, install replacement
turbines at site $12,750
• Lost production & fixed costs
during shutdown $55,400
• Administrative overhead and expenses $15.800
TOTAL $477,000
In view of the high cost to replace a turbine and the expected long term benefits which would
accrue after the process modifications, the project expense was classified non-discretionary. The
Omega Hills process modifications have provided excellent system performance which can be
quantified. To illustrate the economic incentive, a cost savings analysis follows:
• Project Cost - all equipment, labor, etc. $(84.400)
• Return on Investment
Revenues - accrued to reduce maintenance,
increased on-line time
$105 x 2 unit x 14.58 hrs x 12 month = $36,740
hr/turbine month year
Labor Savings - reduction in manhours expended
in maintenance and troubleshooting
(350 hrs x $16.40/hr) = $5,740
Equipment Savings - reduction in material cost,
to maintain engine systems
(240 + 180 + 1200 + 800) x 2 = $4.840
TOTAL ANNUAL SAVINGS $47,320
The payout period at 10% cost of funds is 24 months.
1-13
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LIFE CYCLE ECONOMIC ANALYSIS
Life cycle economics were performed to ascertain the value to WMNA for proceeding with the
process modifications on all existing and projected installations. The following costs were used,
based on WMNAs experience. Numbers are per unit basis:
• Average cost to repair one turbine system $238,500
• Average cost to implement process
modifications & install new filters $42,200
• Average annual savings accrued $23,660
from modifications
• Expected turbine life (in years) 5
normal life cycle between changeout
• Expected turbine life (in years) 2.5
without process modifications
• Scheduled turbine changeout, $133,720
includes cost of downtime
23,660
NEW SYSTEM I
0
0
OLD SYSTEM I
0
Cash Flow - Timetable present value analysis using 10% interest for 10 years. The present
value of the new system is calculated to be:
PVnew* = 23,660+133,720(0.6209+0.3855)
- 2,683 x (6.1445) =
23,660 + 124,575 - 16,487 = $141.748
The present value of the ojd. system costs without the process modifications over ten years would
be:
PVold = $238,500 (0.7889+0.6209+0.4899+0.3855)
+ 13,985x(6.1445) =
545,020+85,930 = $630.950
Over a ten year period, the present value difference is equal to:
$630,950-$141,748 = $489.200 per turbine
WMNA has 25 centaur turbines in operation, which equates to a total company savings of
$12.230.000
1-14
238,500
T
2.5
133,720
j .
5.0
238,500
T
5.0
YEARS
238,500
T
7.5
133,720
-H- . ,.^ T
10.0
238,500
10.0
-------
CONCLUSION
As pointed out in the text and as illustrated in the photos, the improvement in turbine
productivity and the reduction of O&M costs has justified the modifications to the process. The
results have been so overwhelmingly conclusive that Waste Management has decided to install
Pall filtration on all of its twenty seven (27) turbine installations nationwide. All new projects
will include gas conditioning using the process design criteria as established at the Omega Hills
facility in 1988.
Waste Management is the nations leader in landfill gas recovery. In fact 14.5 billion cubic feet
of gas was recovered from 16 facilities during 1990. Currently eight (8) facilities are either in
design or under construction. An additional 10 sites are under consideration for development
in 1991 and 1992.
With the large number of turbine generator systems that will ultimately be in operation and the
high initial investment costs, it becomes evident that gas conditioning plays a vital role in the
overall success of using landfill gas as a fuel in turbine combustion systems.
1-15
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TABLE 1
Composition of Black Deposits Found in Blast Tube Orifices (wt%)
_AL SL .£a_ _Ee_
7.75 71.51 0.52 4.25 1.40 10.6 2.68 1.29
TABLE 2
Composition of Red Deposits Found in #1* Turbine (wt%)
Al Ca Fe _Q_ _S_ _SL Sn
1.86 1.52 9.46 47.89 8.50 26.51 4.26
Red Deposit in #2 Turbine had the same composition.
1-16
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TABLE 3
Liquid/Gas Coalescer and Filter/Separator Performance as Measured in the Field
Hydrocarbon
Sampling Point Content ppmw
Influent to Fil/Sep 0.4536
Effluent of Fil/Sep0) 0.1971
Influent to LG 0.1745
Effluent of LGm 0.0056
(1) All solid aerosols collected on the test membrane were below 25 microns
in diameter.
(2) All solid aerosols collected on the test membrane were well below 1
micron in diameter.
1-17
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CD
-------
^
-------
APPENDIX J: COMPRESSED LANDFILL GAS AS A CLEAN, ALTERNATIVE VEHICLE FUEL (Paper)
Los Angeles County Sanitation Districts
Whittier, California
July, 1993
J-1
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COMPRESSED LANDFILL GAS AS A CLEAN , ALTERNATIVE VEHICLE FUEL
James Stahl, Ed Wheless, and Stan Thalenberg
Los Angeles County Sanitation Districts
Whittier, California
ABSTRACT
The Los Angeles County Sanitation Districts has constructed a compressed landfill
gas fueling facility, located at the Puente Hills. Landfill, which is a fully automatic station
capable of processing and dispensing a high quality compressed gaseous vehicle fuel
derived from landfill gas. The facility is composed of a compression and processing
system, compressed gas storage tanks, and the fuel dispensing station.
The system draws 250 SCFM of landfill gas containing 55% methane, 45% carbon
dioxide, and less than 1% air. This gas is compressed to an intermediate pressure of 525
PSI and then processed through a cellulose acetate membrane for CO2 removal. The
product gas (100 SCFM, or 900 gallons per day diesel equivalent) exiting the membrane
at 500 PSI is further compressed to 3600 PSI and delivered to the storage tanks.
A demonstration program is underway to verify operational performance of a wide
range of vehicles which routinely operate at the landfill using compressed landfill gas.
These vehicles include two refuse trucks, a GMC Sierra Pickup, a GMC water truck, and
one or more refuse transfer tractors. The goal of the demonstration is to verify that landfill
derived fuel can dramatically reduce vehicle emissions while maintaining normally
expected performance.
INTRODUCTION
The Los Angeles County Sanitation Districts (Districts) operate and maintain both
a regional wastewater treatment and solid waste management system which provide
services to approximately 5 million people in Los Angeles County. This involves treating
550 million gallons a day of wastewater and managing the final disposal of approximately
half of the 40,000 tons per day of nonhazardous solid waste landfilled in the county. The
Districts' Puente Hills Landfill, with a nominal fill rate of 12,000 tons per day, produces
over 23,000 SCFM of landfill gas which is collected and used as a fuel to produce
approximately 50 MW of power at an energy recovery (PERG) facility. This landfill is now
generating excess gas which is being used to produce a clean, alternative vehicle fuel.
Although landfill gas has been demonstrated to be an excellent fuel for electrical
power generation, the combination of excess power generating facilities and low cost of
natural gas has resulted in power rates lower than the production costs for new power
J-2
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generating facilities. The production of compressed natural gas (CNG) for use in
vehicles, however, offers the potential of both economic and environmental benefits. A
substantial reduction in air emissions can be achieved if landfill gas, which is being
collected and burned in flares as a method of pollution control, is processed and then
utilized as a diesel substitute to reduce emissions from heavy equipment operating at the
landfill as well as trucks delivering refuse to the landfill. The following provides a
discussion of the refueling facility, the collection and processing system, system
economics, and the vehicle demonstration program under way to obtain operating
experience and establish the potential reduction in emissions.
LANDFILL GAS COLLECTION, PROCESSING, AND COMPRESSION
. The gas collection system at the Puente Hills Landfill is designed to prevent odors
and gaseous releases to the environment by maintaining a negative pressure within the
landfill. To maintain the low surface concentrations of methane consistent with the South
Coast Air Quality Management District Standards, the collected gas contains air drawn
in from the surface of the landfill.
Limited air infiltration, acceptable for flaring or power production, must be held to
very low levels for use as a vehicle fuel. This is necessitated by the California fuel
specification and the difficulty and expense of removing air from the gas through
cryogenic separation. Since the existing gas collection system contains far too much air,
a new pipe line was added to draw, at a slow rate, from several deep wells collecting a
richer "core" gas with less than one percent air. Adjacent wells will be adjusted to insure
that proper surface conditions are maintained. An oxygen sensor at the inlet of the
processing system will continuously monitor for potential air migration and prevent air
diluted gas from entering the system. Although this approach limits the quantity of landfill
gas available for vehicle fuel from a selected site, for the Puente Hills Landfill it would
require less than 5% of the available gas to meet the needs of the on-site mobile
equipment.
After obtaining a high quality landfill gas with limited air contamination, the carbon
dioxide (CO2), hydrogen suffide (H2S), and water vapor must be removed. The CO2,
accounting for 45% of the core gas, would substantially decrease the heating value of the
gas. The hydrogen sulfide amounts to less than 100 ppm of the core gas. However, its
presence even in such a low concentration may lead to corrosion in piping, the storage
tanks, and engines. The water vapor would enhance corrosion problems when
condensed during compression and cooling. In addition to these considerations, the
California Air Resources Board has further established the specifications presented in
Table 1 for vehicle fuel marketed in California to insure consistent emission test results.
This specification was directed primarily at natural gas but also applies to fuel derived
from landfill gas. Changes in methane, ethane, and higher chain hydrocarbons pose
problems with pipeline natural gas and challenges for engine manufacturers. Landfill gas,
when processed, should produce a higher octane, more uniform fuel containing only
methane and small quantities of nitrogen, oxygen, and carbon dioxide. A variety of
J-3
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technologies are available for removing CO2, H2S, and H20. Many of these are
proprietary and are therefore available only through licensed distributors. Some
processes selectively remove only one of the three gases, whereas others remove two
and even all three simultaneously.
TABLE 1
Alternative Fuel Specification for Compressed Natural Gas
Constituent CARS Processing Facility
Requirement
Inlet Product Gas
Methane 88% min 55% min 96%
Ethane 6% max
C3 and Higher 3% max
C6 and higher .2% max
Hydrogen .1% max
Oxygen 1% max .2%
CO .1% max
HC .1% max
Inert Gas (CO^NJ 1.5 - 4.5% range .8% N2 4%
Water .9 #/MMSCF Saturated .5#/MMscf
The Selexol Process and Pressure Swing Adsorption (PSA) are the leading
technologies for production of pipe line quality gas from landfill gas presently in
operation. These processes are capable of producing an acceptable product gas but
both require some form of license and have been predominately applied to large gas
flows of 3 MMSCFD or greater. Both are also normally under steady state, continuous
duty operation with regular but not constant operator attention. Membrane separation
on the other hand is ideally suited to the small quantity of gas being processed and the
need for intermittent, unattended operation. The membrane package is also offered as
an independent unit by several manufacturers much like any other component.
Membrane separation, however, has limited experience with landfill gas cleanup.
Despite the limited landfill gas operating history, the membrane separation
technology was selected for this project. Foremost in this selection was the fact that the
membrane is a passive device which offers the potential, once demonstrated, to utilize
a conventional pipeline gas vehicle fueling station design with the simple addition of the
membrane module. This would expand the number of potential bidders and hopefully
. lead to a lower priced, more reliable product.
J-4
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FACILITY PROCESS DESCRIPTION
The complete unit consists of equipment mounted on three separate skids
designed for automatic, unattended, outdoor operation. The skids include the
compression skid, the membrane skid, and the gas storage skid. In addition, a gas
dispenser is located at a convenient place on the landfill, approximately 1000 feet from
the storage skid. A schematic of the processing system is shown on Figure 1.
The processing unit utilizes 250 scfm of landfill core gas from the dedicated deep
wells as infeed to the system. The gas is saturated with moisture as it enters the system.
A single water knockout tank located on the compressor skid accumulates all the water
that is condensed out during the compression and cooling stages. The condensate from
this facility flows to the main landfill gas condensate collection system for treatment on
site.
The gas is drawn in using a 75 hp rotary vane blower which compresses the gas
to 40 psig. This is followed by a series of heat exchangers and reciprocating compressor
stages which raise the gas pressure to 525 psi and a maximum temperature of 115
degrees.
After compression to 525 psi, the gas passes through an activated carbon guard
bed to remove trace organics. Two guard beds are provided in parallel to allow
regeneration of the bed media without disruption in system operation. The top layer of
each guard bed contains silica gel to reduce water vapor present in the gas. Lowering
the relative humidity of the gas allows for greater hydrocarbon pickup by the activated
carbon, by minimizing the adsorption of water in the carbon pores. The gas then passes
through the activated carbon portion of the bed which selectively adsorbs heavier
hydrocarbon components. The activated carbon used has a higher affinity for sulfur and
halogenated hydrocarbons.
The membranes are particularly susceptible to liquid water damage and in fact
dissolve in water. To eliminate moisture the gas is heated in a glycol water bath and then
fed to the membrane purification elements. The temperature is set to ensure that any
moisture present is in the vapor state. The higher temperature also allows for a more
efficient operation of the membranes.
The gas purification membranes consist of a series of spiral wound cellulose
acetate membrane elements fitted into three separate tubular housings. The tubes are
connected in series. The elements are selectively permeable to carbon dioxide while
rejecting methane. The process is enhanced, within operating limits, by high temperature,
and a high pressure differential across the membranes elements.
The permeate, containing about 28% methane and 72% CO2. is diverted to a
waste gas line and combusted at the energy recovery (PERG) facility. The residual
product gas, now with 96% methane, goes on for further compression and storage. Of
the 250 SCFM feed gas, 150 SCFM is waste gas and 100 SCFM is product gas.
J-5
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Dir.pcnGcr
Storage
Control Puin-l
100 scrn
3600 psi
Storage lonks
v/oste Cos
STAGE 5
COMPRESSION
ISO SCII l-l
20 X CM.I
STAGE 4
COMPRESSION
:_n
A1
a
D-
Membranes
Rc'cytle
Wu tf r
Knockout
Tonk
'55 '' OH
Condenso lt>
Rotary Vane Hr?n I
Lonpressor Exchanger
3000 psi
Dispensei-
Heater
Carbon
Guard
Beds
STAGE 2
CDMPRCSSIGN
3
COMPRESSION
1/Pt
150 psi
Reciprocating Compressors
psi
Figure 1
COMPRESSED LANDFILL GAS
C L. E. A N F" LJ El L. S F~ A C I L. I T Y
-------
After leaving the membranes, the product gas is then odorized. The odorant is
similar to natural gas odorant and serves the same safety function - and early warning
of a leak, tt is metered in so as to be detectable at 1/5 of the lower explosive limit of the
product gas.
The gas is then compressed in a series of stages to a final pressure of 3600 psi
and is stored in three 10.000 standard cubic foot pressure vessels. The tanks are
arranged horizontally and are approximately 23 feet long and 20 inches in diameter.
Underground piping carries the product gas to the gas dispenser is located in an
area easily accessible to vehicles. The entire system design conforms to NFPA 52 which
governs Compressed Natural Gas Vehicular Fuel Systems. The fuel produced conforms
to the California Air Resources Board Proposed Alternative Fuel Specification For
Compressed Natural Gas. As such, the product fuel can be used on any vehicle
designed to run on compressed natural gas with predictable air emissions.
REFUELING FACILITY DESCRIPTION
To provide a fast fill operation, 30,000 SCF of CNG is stored in three vessels at
3,600 psig. The vessels are emptied sequentially during vehicle refueling such that the
first vessel provides CNG until the vehicle tank reaches 3,000 psig or the pressures
equalize at which point the second storage vessel will deliver CNG followed by the third
vessel if required. When the first vessel pressure starts to decay the gas compressors
will start automatically to replace the gas. If the vehicle is still not full after the last vessel
is equalized with the vehicle the compressor will provide CNG directly to the vehicle. In
this mode the fill time will be less than ten minutes for a light duty vehicle extending to
over an hour to transfer the equivalent of 50 gallons of diesel.
The fuel dispenser is similar to a conventional gasoline pump with two fill hoses,
a fuel meter, and an automatic card operated system to initiate operation and record
billing information. One of the dispensing hoses is equipped with a Sherex 5000 nozzle
for fast filling 8,000 SCF (57 gallons equivalent of diesel) in less than ten minutes. The
second hose has a Sherex 1000 nozzle which will rapidly fill light duty trucks or
passenger vehicles.
ECONOMICS
The facility cost, including design, construction, and initial startup was $900,000 for
the complete system excluding the piping from the dedicated wells. A cost breakdown
is provided in Table II. This cost was obtained through competitive, sealed bids in
response to a detailed functional specification developed by the Districts for the turnkey
services. The applicable taxes and District staff costs related to engineering, construction
management, and inspection brings the total cost to approximately one million dollars.
J-7
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TABLE II
REFUELING FACILITY COST BREAKDOWN
ITEM COST
Compressor skid 175,000
Membrane skid 110,000
Dispenser 50,000
Storage 40,000
Instrumentation/Controls 115,000
Electrical 100,000
Miscellaneous 60,000
Engineering, Overhead, & profit 250.000
TOTAL CONSTRUCTION COST $900,000
The operating costs are presented in Table III in terms of cents per gallon of
gasoline for 25%, 50%, and fuH station utilization. Since capital recovery of construction
costs represent a majority of the fuel production cost, fuel usage is key to low cost
production.
TABLE III
FUEL COST
UTILIZATION COST PER GAL GASOLINE EQUIVALENT
100% 48C
50% 74<5
25% 126C
Basis: Capital recovery, 15 yrs. @ 7%
Power, 5C/kw-hr
O & M, 3% of construction cost
Gallon of Gasoline = 125 scf of CNG
VEHICLE DEMONSTRATION PROGRAM
In late 1991, the Districts initiated a program to utilize landfill gas as a clean
burning alternative fuel for District vehicles and heavy-duty equipment. The program also
envisioned that fuel could be made available to users of the landfill to further reduce air
J-8
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emissions and dependence on petroleum products. The program is primarily dependent
on the engine manufacturers ability to produce low emission, dedicated CNG engines.
This is an emerging technology with a limited number of equipment suppliers who move
very slowly in product development. This has been the major factor in shaping the
program outlined below.
Light-Duty Vehicles
In late 1991, the Districts ordered a GMC 3/4 ton Sierra pickup in place of a normal
gasoline model. This vehicle was one of 1,000 light-duty vehicles produced by GMC
Truck Division with assistance from the local gas company and others. The vehicle was
delivered in mid 1992. The initial operating experience included poor performance, limited
miles per tank or gallon equivalent, and lack of training of the dealer service personnel.
The performance has improved and is now equivalent to a normal gasoline engine
version but the mileage has not improved. Additional purchases will be dependent on
GMC ability to correct this problem.
Medium Duty
A dedicated natural gas water truck was purchased in mid 1992. This truck is a
GMC with a Hercules 5.6 liter engine. This engine is provided with a factory warranty.
This truck is expected to be operational at the Puente Hills Landfill by April 1993.
Refuse Trucks
Two private refuse collection companies will be participating in a program with the
Districts with funding provided by the South Coast Air Quality District to repower a refuse
packer and a roll-off. The packer is a Volvo-White which will be powered by a Detroit
Diesel Series 50 dedicated CNG spark ignited diesel engine. The roll-off is an
International which will be powered by a CAT 3306 dedicated CNG engine. Both engines
carry warranties from the engine manufacturer and are expected to have low emissions.
Both trucks are expected to be operational in mid 1993 and will be evaluated over at least
a one year period. Air emission testing will be conducted on both engines.
Heavy Duty Vehicles
The Districts plans to also initiate a demonstration program for a refuse transfer
tractor and a landfill dozer. The heavy duty on-road program should be underway in
1993. Off-road equipment development is still awaiting firm commitments from equipment
suppliers but should be initiated in 1994.
J-9
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At the 17th Annual Landfill Gas Symposium, a follow-up of the previous paper was presented which
describes the experience with the landfill gas clean-up and compression system and the utilization of
compressed landfill gas (CLG) in various vehicles. Excerpts from this presentation are presented
below.
From "Processing and Utilization of Landfill Gas as a Clean Alternative Vehicle Fuel" by Steve Maguin,
Ed Wheless, and Monet Wong. Los Angeles County Sanitation Districts, Whittier, California. 17th
Annual Landfill Gas Symposium, March 22-24, 1994, Long Beach, California.
OPERATIONAL PERFORMANCE
The refueling facility was formally accepted from the contractor and placed in service in October 1993.
With the limited number of vehicles running on CNG, the fuel dispensed through February 1994
totalled less than the equivalent of 2,200 gallons of gasoline. Although this corresponds to only 2
days of continuous operation, the basic design and technology appears to be successful.
During this early phase of operation, the membrane has consistently delivered a product gas
averaging 97% methane with 96% as the minimum. The compression and processing system was
available to deliver product gas on demand 82% of the time. This was even better for the dispenser,
with 94% availability due to gas storage and limited facility use. Although the processing system
would only need to operate less than half an hour per day to produce the fuel delivered, the gas
compressors have averaged over 3 hours of run time per day. The additional run time was needed
to satisfy process needs which included achieving proper operating parameters during start-up,
providing the fuel for the heater, and providing purge gas to the first stage compressor and membrane
upon shutdown. In many ways, this intermittent, short duration operation may be a more stringent
requirement than continuous operation.
The operational problems experienced during start-up and initial operation have not been related to
landfill gas processing. Instead they could be associated with facility process design and could accrue
with normal pipeline gas refueling systems. This included problems with the dispenser and associated
card reader, the odorant addition system, and the process instrumentation. The compressors have
also experienced several failures, but none attributable to the landfill gas.
The process is presently being reviewed to determine how the operation could be simplified and
improved. Items under investigation include the use of heat from the compressors to replace the gas
heater, elimination or simplification of the carbon guard bed, and restricting the purge gas usage.
These modifications would greatly simplify the process and make the system comparable to the
standard pipeline CNG compression stations.
J-10
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VEHICLE DEMONSTRATION PROGRAM (update)
Summary
In addition to producing a clean vehicle fuel, the Districts' program involves the demonstration of CNG
vehicles, and possibly off-road heavy-duty equipment, at the Puente Hills Landfill using the
compressed landfill gas (CLG). The fuel is also being provided to a refuse hauler using the landfill
to demonstrate how CLG could further reduce emissions and dependence on petroleum products.
The program has been primarily dependent on the engine manufacturers' ability to produce low
emission, dedicated CNG engines. This is an emerging technology with a limited number of
equipment suppliers who move very slowly in product development. A summary of recent experience
with vehicles running on CLG is presented in the table below.
TYPE OF VEHICLE FUEL
PERFORMANCE
MILES PER GALLON
(gasoline/diesel
equivalent on CLG)
EMISSIONS
Passenger Vehicle
Light Duty Truck
Medium Duty
Vehicles (planned)
Heavy Duty Truck
(water truck)
Heavy Duty Truck
(packer truck)
Other Heavy Duty
Vehicles (including
a tractor)
Either CNG or gasoline
Performed very well on 21 (gasoline)
CLG
CNG at first, later only CLG Initial operation was poor. 9 (gasoline)
OK after modifications.
Planned
Note: The newest types of minivans should meet ULEV standards
CLG
CLG (CNG back up)
Planned
No problems reported 2.4 (diesel)
Initially superior 2.3 (diesel)
performance and power.
Recently slight decrease in
power (under investigation)
No data
Low in NMHC and NO,
(compared to gas).
Meets LEV standards
except for NMHC.
Meets 1994 CARB
standards. No exhaust
after- treatment
necessary.
Meets 1994 CARB
standards. Except for
NO, emissions are
considerably lower than
standards
CARB = California Air Resources Board
CLG = compressed LFG
LEV = Low Emissions Vehicle
ULEV = Ultra Low Emissions Vehicle
J-11
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THE FUTURE
The long-term practical use of a compressed natural gas produced from landfill gas is dependent on
both the ability of engine manufacturers to produce low-emission dedicated CNG engines and the
economics of producing the fuel. The Districts will continue to work with the SCAQMD and engine
manufacturers to study new engine technologies which can reduce air emissions from the equipment
and vehicles using the landfill and thus improve the air quality in the South Coast Air Basin.
The engine technology is rapidly emerging as demonstrated by Chrysler's dedicated CNG Minivans
introduced this year which are leading the way for light-duty vehicles with emissions which are less
than one tenth the CARB's ULEV standards. The existing heavy-duty CNG engines are cleaner than
diesel but additional breakthroughs such as the plasma charge engine scheduled for demonstration
later this year is needed to achieve the very low emissions needed.
The technology for producing a clean fuel from landfill gas has been demonstrated. The economics,
however, will be dependent upon the amount of gas being processed. The processing capacity of the
District's fueling facility represents the minimum economical size. Many of the components such as
the dispenser, storage, and continuous monitors are independent of processing capacity while costs
related to engineering design, compressors, and the membrane are expected to increase by only 50%
if the capacity doubles. If the fleet of vehicles is large enough to justify a larger facility, the price per
gallon equivalent can be expected to drop to approximately half the existing cost of diesel or gasoline.
If diesel or gasoline prices increase on the other hand, even smaller facilities may be attractive.
J-12
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APPENDIX K: THREE EPA MEMORANDA ON NEW SOURCE REVIEW RELATING TO
LANDFILLS AND LANDFILL GAS
CLASSIFICATION OF EMISSIONS FROM LANDFILLS FOR NEW SOURCE REVIEW
APPLICABILITY PURPOSES (K-2) (J. Seitz, 10/21/94)
EMISSIONS FROM LANDFILLS (K-6) (G. Emison, 10/6/87)
POLLUTION CONTROL PROJECTS AND NEW SOURCE REVIEW (NSR) APPLICABILITY
(K-8) (J. Seitz, 7/1/94)
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK. NC 2771 1
October 21, 1994
OFFICE OF
AIR QUALITY PLANNING
AND STANDARDS
MEMORANDUM
SUBJECT:
FROM:
TO:
Classification of Emissions from Landfills for
NSR Applicability Purposes
John S. Seitz, Director
Office of Air Quality P
ng and Standa
(MD-10)
Director, Air, Pesticides and Toxics
Management Division, Regions I and IV
Director, Air and Waste Management Division,
Region II
Director, Air, Radiation and Toxics Division,
Region III
Director, Air and Radiation Division,
Region V
Director, Air, Pesticides and Toxics Division,
Region VI
Director, Air and Toxics Division,
Regions VII, VIII, IX and X
The EPA has recently received several inquiries regarding
the treatment of emissions from landfills for purposes of major
NSR applicability. The specific issue raised is whether the
Agency still considers landfill gas emissions which are not
collected to be fugitive for NSR applicability purposes.
The EPA's NSR regulations define "fugitive emissions" to
mean "those emissions which could not reasonably pass through a
stack, chimney, vent, or other functionally-equivalent opening"
(40 CFR 51.165(a)(1)(x)). In general, where a facility is not
subject to national standards requiring collection, the technical
question of whether the emissions at a particular site could
"reasonably pass through a stack, chimney, vent, or other
functionally-equivalent opening" is a factual determination to be
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made by the permitting authority, on a case-by-case basis. In
determining whether emissions could reasonably be collected (or
if any emissions source could reasonably pass through a stack,
etc.)/ "reasonableness" should be construed broadly. The
existence of collection technology in use by other sources in the
source category creates a presumption that collection is
reasonable. Furthermore, in certain circumstances, the
collection of emissions from a specific pollutant emitting
activity can create a presumption that collection is reasonable
for a similar pollutant-emitting activity, even if that activity
is located within a different source category.
In 1987, EPA addressed whether landfill gas emissions should
be considered as fugitive.1 The Agency explained that for
landfills constructed or proposed to be constructed with gas
collection systems, the collected landfill gas would not qualify
as fugitive. Also, the Agency understood at the time that, with
some exceptions, landfills were not constructed with such gas
collection systems. The EPA explained that "[t]he preamble to
the 1980 NSR regulations characterizes nonfugitive emissions as
x. . . emissions which would ordinarily be collected and
discharged through stacks or other functionally equivalent
openings'" (see 45 FR 52693, Aug. 7, I960).2 Based on the
"understanding that landfills are not ordinarily constructed with
gas collection systems," the Agency concluded that "emissions
from existing or proposed landfills without gas collection
systems are to be considered fugitive emissions." The Agency
also made clear, however, that the applicant's decision on
whether to collect emissions is not the deciding factor. Rather,
it is the reviewing authority that makes the decision regarding
1See memorandum entitled "Emissions from Landfills," from
Gerald A. Emison, Director, Office of Air Quality Planning and
Standards, to David P. Howekamp, Director, Air Management
Division, Region IX, dated October 6, 1987 (attached). It is
important to note that the interpretation contained in this
memorandum was only applicable to landfills.
2In fact, the 1980 preamble language recognized the concern
that sources could avoid NSR by calling emissions fugitives, even
if the source could capture those emissions. The EPA's
originally-proposed definition of fugitive emissions was changed
in the final 1980 regulations to "ensure that sources will not
discharge as fugitive emissions those emissions which would
ordinarily be collected and discharged through stacks or other
functionally equivalent openings, and will eliminate
disincentives for the construction of ductwork and stacks for the
collection of emissions." Id.
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which emissions can reasonably be collected and therefore not
considered fugitive.
The EPA believes its 1987 interpretation of the 1980
preamble may have been misunderstood, and in any case that its
factual conclusions at that time are now outdated. Continued
misunderstanding or application of this outdated view could
discourage those constructing new landfills from utilizing
otherwise environmentally- or economically-desirable gas
collection and mitigation measures in order to avoid major NSR
applicability.
Specifically with regard to landfill gas emissions, gas
collection and mitigation technologies have evolved significantly
since 1987, and use of these systems has become much more common.
Increasingly, landfills are constructed or retrofitted with gas
collection systems for purposes of energy recovery and in order
to comply with State and Federal regulatory requirements designed
to address public health and welfare concerns. In addition, EPA
has proposed performance standards for new landfills under
section lll(b) of the Clean Air Act and has proposed guidelines
for existing landfills under section lll(d) that, when
promulgated, will require gas collection systems for existing and
new landfills that are above a certain size and gas production •
level (see 56 FR 24468, May 30, 1991). Under these requirements,
EPA estimates that between 500 and 700 medium and large landfills
will have to collect and control landfill gas. The EPA believes
this proposal created a presumption at that time that the
proposed gas collection systems, at a minimum, are reasonable for
landfills that would be subject to such control under the
proposal.
Thus, EPA believes it is no longer appropriate to conclude
generally that landfill gas'could not reasonably be collected at
a proposed landfill project that does not include a gas
collection system. The fact that a proposed landfill project
does not include a collection system in its proposed design is
not determinative of whether emissions from a landfill are
fugitive. To quantify the amount of landfill gas which could
otherwise be collected at a proposed landfill for NSR
applicability purposes, the air pollution control authority
should assume the use of a collection system which has been
designed to maximize, to the greatest extent possible, the
capture of air pollutants from the landfill.
In summary, the use of collection technology by other
landfill sources, whether or not subject to EPA's proposed
requirements or to State implementation plan or permit
requirements, creates a presumption that collection of the
emissions is reasonable at other similar sources. If such a
system can reasonably be designed to collect the landfill's gas
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emissions, then the emissions are not fugitive and should be
considered in determining whether a major NSR permit is required.
Today's guidance is applicable to the construction of a new
landfill or the expansion of an existing landfill beyond its
currently-permitted capacity. To avoid any confusion regarding
the applicability of major NSR to existing landfills, EPA does
not plan to reconsider or recommend that States reconsider the
major NSR status of any existing landfill based on the issues
discussed in this memorandum. Also, nothing in this guidance
voids or creates an exclusion from any otherwise applicable
requirement under the Clean Air Act and the State implementation
plan, including minor source review.
The Regional Offices should send this memorandum, including
the attachment, to States within their jurisdiction. Questions
concerning specific issues and cases should be directed to
the appropriate Regional Office. Regional Office staff may
contact Mr. David Solomon, Chief, New Source Review Section, at
(919) 541-5375, if they have any questions.
Attachment
cc: Air Branch Chief, Regions I-X
NSR Contacts, Regions I-X and Headquarters •
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
5 Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
'"V
OCT 6 1987
MEMORANDUM
SUBJECT: Emissions from Landfills
FROM: / Gerald A. Emison, Director
/ era . mson, recor-* — -r-^~- T*-.-
"FT.. Office of Air Quality Planning and Standards (MD-10)
TO: David P. Howekamp, Director
Air Management Division, Region IX
This is in response to your September 1, 1987, memorandum requesting
clarification regarding how landfill emissions should be considered for the
purpose of determining nonattainment new source review (NSR) applicability
under 40 CFR 51.18.
As you are aware, a landfill is subject to NSR if its potential to
emit, excluding fugitive emissions, exceeds the 100 tons per year applicable
major source cutoff for the pollutant for which the area is nonattainment.
Fugitive emissions are defined in 40 CFR (j)(l)(ix) as ". . . those emissions
which could not reasonably pass through a stack, chimney, vent, or other
functionally equivalent opening." Landfill emissions that could reasonably
be collected and vented are therefore not considered fugitive emissions
and must be included in calculating a source's potential to emit.
For various reasons (e.g., odor and public health concerns, local
regulatory requirements, economic incentives), many landfills are
constructed with gas collection systems. Collected landfill gas may be
flared, vented to the atmosphere, or processed into useful energy end
products such as high-Btu gas, steam, or electricity. In these cases, for
either an existing or proposed landfill, it is clear that the collected
landfill gas does not qualify as fugitive emissions and must be included
in the source's potential to emit when calculating NSR applicability.
The preamble to the 1980 NSR regulations characterizes nonfugitive
emissions as "... those emissions which would ordinarily be collected and
discharged through stacks or other functionally equivalent openings."
Although there are some exceptions, it is our understanding that landfills
are not ordinarily constructed with gas collection systems. Therefore,
emissions from existing or proposed landfills without gas collection
systems are to be considered fugitive emissions and are not included in the
NSR applicability determination. This does not mean that the applicant's
decision on whether to collect emissions is the deciding factor; in fact,
the reviewing authority makes the decision on which emissions would
ordinarily be collected and which therefore are not considered fugitive
emissions.
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It should be noted that NSR applicability is pollutant specific.
Therefore, where the landfill gas is flared or otherwise combusted or
processed before release to the atmosphere, it is the pollutant released
which counts toward NSR applicability. As an example, landfill gas is
composed mostly of volatile organic compounds, but when this gas is burned
in a flare, it is the type and quantity of pollutants in the exhaust gas
(e.g., nitrogen oxides and carbon monoxide) that are used in the NSR
applicability determination.
If you have any questions regarding this matter, please contact
Gary McCutchen, Chief, New Source Review Section, at FTS 629-5592.
cc: Chief, Air Branch
Regions I-X
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'*ff
> UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
3 RESEARCH TRIANGLE PARK. NC 27711
JUL I 1994
OFFICE OF
AIR QUALITY PLANNING
AND STANDARDS
MEMORANDUM
SUBJECT: Pollution Control Projects and New S/^tc^e Review (NSR)
Applicability
S. Seitz, Directoi
'fi Office of Air Quality p££Kning/anld Standards (MD-10)
TO: Director, Air, Pesticides and Toxics
Management Division, Regions I and IV
Director, Air and Waste Management Division,
Region II
Director, Air, Radiation and Toxics Division,
Region III
Director, Air and Radiation Division,
Region V
Director, Air, Pesticides and Toxics Division,
Region VI
Director, Air and Toxics Division,
Regions VII, VIII, IX and X
This memorandum and attachment address issues involving the
Environmental Protection Agency's (EPA's) NSR rules and guidance
concerning the exclusion from major NSR of pollution control
projects at existing sources. The attachment provides a full
discussion of the issues and this policy, including illustrative
examples.
For several years, EPA has had a policy of excluding certain
pollution control projects from the NSR requirements of parts C
and D of title I of the Clean Air Act (Act) on a case-by-case
basis. In 1992, EPA adopted an explicit pollution control
project exclusion for electric utility generating units [see :
57 FR 32314 (the "WEPCO rule" or the "WEPCO rulemaking")]. At
the time, EPA indicated that it would, in a subsequent
rulemaking, consider adopting a-formal pollution control project
exclusion for other source categories [see 57 FR 32332]. In the
interim, EPA stated that individual pollution control projects
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involving source categories other than utilities could continue
to be excluded from NSR by permitting authorities on a case-by-
case basis [see 57 FR at 32320]. At this time, EPA expects to
complete a rulemaking on a pollution control project exclusion
for other source categories in early 1996. This memorandum and
attachment provide interim guidance for permitting authorities on
the approvability of these projects pending EPA's final action on
a formal regulatory exclusion.
The attachment to this memorandum outlines in greater detail
the type of projects that may qualify for a conditional exclusion
from NSR as a pollution control project, the safeguards that are
to be met, and the procedural steps that permitting authorities
should follow in issuing an exclusion. Projects that do not meet
these safeguards and procedural steps do not qualify for an
exclusion from NSR under this policy. Pollution control projects
potentially eligible for an exclusion (provided all applicable
safeguards are met) include the installation of conventional or
innovative emissions control equipment and projects undertaken to
accommodate switching to an inherently less-polluting fuel, such
as natural gas. Under this guidance, States nay also exclude as
pollution control projects some material and process changes
(e.g., the switch to a less polluting coating, solvent, or
refrigerant) and some other types of pollution prevention
projects undertaken to reduce emissions of air pollutants subject
to regulation under the Act.
The replacement of an existing emissions unit with a newer
or different one (albeit more efficient and less polluting) or
the reconstruction of an existing emissions unit does not qualify
as a pollution control project. Furthermore, this guidance only
applies to physical or operational changes whose primary function
is the reduction of air pollutants subject to regulation under -•
the Act at existing major sources. This policy does not apply to
air pollution controls and emissions associated with a proposed
new source. Similarly, the fabrication, manufacture or
production of pollution control/prevention equipment and
inherently less-polluting fuels or raw materials are not
pollution control projects under this policy (e.g., a physical or
operational change for the purpose of producing reformulated
gasoline at a refinery is not a pollution control project).
It is EPA's experience that many bona fide pollution control
projects are not subject to major NSR requirements for the simple
reason that they result in a reduction in annual emissions at the
source. In this way, these pollution control projects are
outside major NSR coverage in accordance with the general rules
for determining applicability of NSR to modifications at existing
sources. However, some pollution control projects could result
in significant potential or actual increases of some pollutants.
These latter projects comprise the subcategory of pollution
control projects that can benefit from this guidance.
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A pollution control project must be, on balance,
"environmentally beneficial" to be eligible for an exclusion.
Further, an environmentally-beneficial pollution control project
„ may be excluded from otherwise applicable major NSR requirements
r only under conditions that ensure that the project will not cause
brt contribute to a violation of a national ambient air quality
standard (NAAQS), prevention of significant deterioration (PSD)
increment, or adversely affect visibility or other air quality
related value (AQRV). In order to assure that air quality
concerns with these projects are adequately addressed, there are
two substantive and two procedural safeguards which are to be
followed by permitting authorities reviewing projects proposed
for exclusion.
First, the permitting authority must determine that the
proposed pollution control project, after consideration of the
reduction in the targeted pollutant and any collateral effects,
will be environmentally beneficial. Second, nothing in this
guidance authorizes any pollution control project which wpuld
cause or contribute to a violation of a NAAQS, or PSD increment,
or adversely impact an AQRV in a class I area. Consequently, ;in
addition to this "environmentally-beneficial11 standard, the
permitting authority must ensure that adverse collateral
environmental impacts from the project are identified, minimized,
and, where appropriate, mitigated. For example, the source or
the State must secure offsetting reductions in the case of a
project which will result in a significant increase in a
nonattainment pollutant. Where a significant collateral increase
in actual emissions is expected to result from a pollution
control project, the permitting authority must also assess
whether the increase could adversely affect any national ambient
air quality standard, PSD increment, or class I AQRV.
In addition to these substantive safeguards, EPA is
specifying two procedural safeguards which are to be followed.
First, since the exclusion under this interim guidance is only
available on a case-by-^case basis, sources seeking exclusion from
major NSR requirements prior to the forthcoming EPA ruleraaking on
a pollution control project exclusion must, before beginning
construction, obtain a determination by the permitting authority
that a proposed project qualifies for an exclusion from major NSR
requirements as a pollution control project. Second, in
considering this request, the permitting authority must afford
the public an opportunity to review and comment on the source's
application for this exclusion. It is also important to note
that any project excluded from major new source review as a
pollution control project must still comply with all otherwise
applicable requirements under the Act and the State
implementation plan (SIP), including minor source permitting.
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This guidance document does not supersede existing Federal
or State regulations or approved SIP's. The policies set out in
this memorandum and attachment are intended as guidance to be
applied only prospectively (including those projects currently
under evaluation for an exclusion) during the interim period
until EPA takes action to revise its NSR rules, and do not
represent final Agency action. This policy statement is not ripe
for judicial review. Moreover, it is not intended, nor can it be
relied upon, to create any rights enforceable by any party in
litigation with the United States. Agency officials may decide
to follow the guidance provided in this memorandum, or to act at
variance with the guidance, based on an analysis of specific
circumstances. The EPA also may change this guidance at any time
without public notice. The EPA presently intends to address the
matters discussed in this document in a forthcoming NSR
rulemaking regarding proposed changes to the program resulting
from the NSR Reform process and will take comment on these
matters as part of that rulemaking.
As noted .above, a detailed discussion of the types of
projects potentially eligible for an exclusion from major NSR 'as
a pollution control project, as well as the safeguards such
projects must meet to qualify for the exclusion, is contained in
the attachment to this memorandum. The Regional Offices should
send this memorandum with the attachment to States within their
jurisdiction. Questions concerning specific issues and cases
should be directed to the appropriate EPA Regional Office.
Regional Office staff may contact David Solomon, Chief, New
Source Review Section, at (919) 541-5375, if they have any
questions.
Attachment
cc: Air Branch Chief, Regions I-X
NSR Reform Subcommittee Members
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Attachment
GUIDANCE ON EXCLUDING POLLUTION CONTROL PROJECTS
FROM MAJOR NEW SOURCE REVIEW (NSR)
I. Purpose
The Environmental Protection Agency (EPA) presently expects
to complete a rulemaking on an exclusion from major NSR for
pollution control projects by early 1996. In the interim,
certain types of projects (involving source categories other than
utilities) may qualify on a case-by-case basis for an exclusion
from major NSR as pollution control projects. Prior to EPA's
final action on a regulatory exclusion, this attachment provides
interim guidance for permitting authorities on the types of
projects that may qualify on a case-by-case basis .from major NSR
as pollution control projects, including the substantive and
procedural safeguards which apply.
II. Background
The NSR provisions of part C [prevention of significant
deterioration (PSD)] and part D (nonattainment requirements) of
title I of the Clean Air Act (Act) apply to both the construction
of major new sources and the modification of existing major
sources.1 The modification provisions of the NSR programs in
parts C and D are based on the broad definition of modification
in section 111(a)(4) of the Act. That section contemplates a
two-step test for determining whether activities at an existing
major facility constitute a modification subject to new source
requirements. In the first step, the reviewing authority
determines whether a physical or operational change will occur.
In the second step, the question is whether the physical or
operational change will result in any increase in emissions of
any regulated pollutant.
The definition of physical or operational change in
section 111(a)(4) could, standing alone, encompass the most
mundane activities at an industrial facility (even the repair or
replacement of a single leaky pipe, or a insignificant change in
the way that pipe is utilized). However, EPA has recognized that
Congress did not intend to make every activity at a source
subject to new source requirements under parts C and D. As a
result, EPA has by regulation limited the reach of the
modification provisions of parts C and D to only major
modifications. Under NSR, a "major modification" is generally a
physical change or change in the method of operation of a major
etationary source which would result in a significant net
emissions increase in the emissions of any regulated pollutant
'The EPA's NSR regulations for nonattainment areas are set
forth at 40 CFR 51.165, 52.24 and part 51, Appendix S. The PSD
program is set forth in 40 CFR 52.21 and 51.166.
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[see, e.g., 40 CFR 52.21(b)(2) (i)] . A "net emissions increase"
is defined as the increase in "actual emissions" from the
particular physical or operational change together with any other
contemporaneous increases or decreases in actual emissions [see,
e.g., 40 CFR 52.21(b)(3)(i)]. In order to trigger major new
source review, the net emissions increase must exceed specified
11 significance" levels [see, e.g., 40 CFR 52.21(b) (2) (i) and 40
CFR 52.21(b)(23)]. The EPA has also adopted common-sense
exclusions from the "physical or operational change" component of
the definition of "major modification." For example, EPA's
regulations contain exclusions for routine maintenance, repair,
and replacement; for certain increases in the hours of operation
or in the production rate; and for certain types of fuel switches
[see, e.g., 40 CFR 52.21(b)(2)(iii)].
In the 1992 "WEPCO" rulemaking [57 FR 32314], EPA amended
its PSD and nonattainment NSR regulations as they pertain to
utilities by adding certain pollution control projects to the
list of activities excluded from the definition of physical or
operational changes. In taking that action, EPA stated it was
largely formalizing an existing policy under which it had been
excluding individual pollution control projects where it was
found that the project "would be environmentally beneficial,
taking into account ambient air quality" [57 FR at 32320; see
also id., n. 15].2
The EPA has provided exclusions for pollution control
projects in the form of "no action assurances" prior to
November 15, 1990 and nonapplicability determinations based on
Act changes as of November 15, 1990 (1990 Amendments).
Generally, these exclusions addressed clean coal technology
projects and fuel switches at electric utilities.
Because the WEPCO rulemaking was directed at the utility
industry which faced "massive industry-wide undertakings of
pollution control projects" to comply with the acid rain
provisions of the Act [57 FR 32314], EPA limited the types of
projects eligible for the exclusion to add-on controls and fuel
switches at utilities. Thus", pollution control projects under
the WEPCO rule are defined as:
any activity or project undertaken at an
existing electric utility steam generating
unit for purposes of reducing emissions from
such unit. Such activities or projects are
limited to;
guidance pertains only to source categories other than
electric utilities, and EPA does not intend for this guidance to
affect the WEPCO rulemaking in any way.
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(A) The installation of conventional or
innovative pollution control technology,
including but not limited to advanced - flue
gas desulfurization, sorbent injection for
sulfur dioxide (SO2) and nitrogen oxides (NOJ
controls and electrostatic precipitators;
(B) An activity or project to accommodate
switching to a fuel which is less polluting
than the fuel in use prior to the activity or
project ...
[40 CFR 51.165(a)(1)(xxv) (emphasis added)].
The definition also includes certain clean coal technology
demonstration projects. Id.
The EPA built two safeguards into the exclusion in the
rulemaking. First, a project that meets the definition of
pollution control project will not qualify for the exclusion
where the "reviewing authority determines that (the proposed
project) renders the unit less'environmentally beneficial ..."
[see, e.g., 51.l65(a)(1)(v)(C)(8)]. In the WEPCO rule, EPA did
not provide any specific definition of the environmentally-
beneficial standard, although it did indicate that the pollution
control project provision "provides for a case-by-case assessment
of the pollution control project's net emissions and overall
impact on the environment" [57 FR 32321]. This provision is
buttressed by a second safeguard that directs permitting
authorities to evaluate the air quality impacts of pollution
control projects that could—through collateral emissions
increases or changes in utilization patterns—adversely impact
local air quality [see 57 FR 32322]. This provision generally
authorizes, as appropriate, a permitting authority to .require
modelling of emissions increases associated with a pollution
control project. Id. More fundamentally, it explicitly states
that no pollution control project under any circumstances may
cause or contribute to violation of a national ambient air
quality standard (NAAQS) , PSD increment, or air quality related
value (AQRV) in a class I area. Id.3
3The WEPCO rule refers specifically to "visibility
limitation" rather than "air quality related values." However,
EPA clearly stated in the preamble to the final rule that
permitting agencies have the authority to "solicit the views of
others in taking any other appropriate remedial steps deemed
necessary to protect class I areas. . .. The EPA emphasizes that
all environmental impacts, including those on class I areas, can
be considered. . .." [57 FR 32322]. Further, the statutory
protections in section 165(d) plainly are intended to protect
against any "adverse impact on the AQRV of such [class I] lands
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As noted, the WEPCO rulemaking was expressly limited to
existing electric utility steam generating units [see, e.g., 40
CFR 51.165(a)(1)(v)(C)(8) and 51.165(a)(1)(xx)]. The EPA limited
the rulemaking to utilities because of the impending acid rain
requirements under title IV of the Act, EPA's extensive
experience with new source applicability issues for electric
utilities, the general similarity of equipment, and the public
availability of utility operating projections. The EPA indicated
it would consider adopting a formal NSR pollution control project
exclusion for other source categories as part of a separate NSR
rulemaking. The rulemaking in question is now expected to be
finalized by early 1996. On the other hand, the WEPCO rulemaking
also noted that EPA's existing policy was, and would continue to
be, to allow permitting authorities to exclude pollution control
projects in other source categories on a case-by-case basis.
III. Case-By-Case Pollution Control Project Determinations
The following sections describe the type of projects that
may be considered by permitting authorities for exclusion from
major NSR as pollution control projects and two safeguards that
permitting authorities are to use in evaluating such projects—
the environmentally-beneficial test and an air quality impact
assessment. To a large extent, these requirements are drawn from
the WEPCO rulemaking. However, because the WEPCO rule was
designed for a single source category, electric utilities, it
cannot and does not serve as a complete template for this
guidance. Therefore, the following descriptions expand upon the
WEPCO rule in the scope of qualifying projects and in the
specific elements inherent in the safeguards. These changes
reflect the far more complicated task of evaluating pollution
control projects at a wide variety of sources facing a myriad of
Federal, State, and local clean air requirements.
Since the safeguards are an integral component of the
exclusion, States must have the authority to impose the
safeguards in approving an exclusion from major NSR under this
policy. Thus, State or local permitting authorities in order to
use this policy should provide statements to EPA describing and
affirming the basis for its authority to impose these safeguards
absent major NSR. Sources that obtain exclusions from permitting
authorities that have not provided this affirmation of authority
are at risk in seeking to rely on the exclusion issued by the
(including visibility)." Based on this statutory provision, EPA
believes that the proper focus of any air quality assessment for
a pollution control project should be on visibility and any other
relevant AQRV's for any class I areas that may be affected by the
proposed project. Permitting authorities should notify Federal
Land Managers where appropriate concerning pollution control
projects which may adversely affect AQRV's in class I areas.
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permitting agency, because EPA may subsequently determine that
the project does not qualify as a pollution control project under
this policy.
A. Types of Projects Covered
1. Add-On Controls and Fuel Switches
In the WEPCO rulemaking, EPA found that both add-on
emissions control projects and fuel switches to less-polluting
fuels could be considered to be pollution control projects. For
the purposes of today's guidance/ EPA affirms that these types of
projects are appropriate candidates for a case-by-case exclusion
as well. These types of projects include:
the installation of conventional and advanced flue gas
desulfurization and sorbent injection for S02;
electrostatic precipitators, baghouses, high efficiency
multiclones, and scrubbers for particulate or other .
pollutants;
flue gas recirculation, low-NO, burners, selective non-
catalytic reduction and selective catalytic reduction for
NOX; and
regenerative thermal oxidizers (RTO), catalytic
oxidizers, condensers, thermal incinerators, flares and
carbon adsorbers for volatile organic compounds (VOC)
and toxic air pollutants.
Projects undertaken to accommodate switching to an
inherently less-polluting fuel such as natural gas can also
qualify for the exclusion. Any activity that is necessary to
accommodate switching to a inherently less-polluting fuel is
considered to be part of the pollution control project. In some
instances, where the emissions unit's capability would otherwise
be impaired as a result of the fuel switch, this may involve
certain necessary changes to the pollution generating equipment
(e.g., boiler) in order to maintain the normal operating
capability of the unit at the time of the project.
2. Pollution Prevention Projects
It is EPA's policy to promote pollution prevention
approaches and to remove regulatory barriers to sources seeking
to develop and implement pollution prevention solutions to the
extent allowed under the Act. For this reason, permitting
authorities may also apply this exclusion to switches to
inherently less-polluting raw materials and processes and certain
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other types of "pollution prevention" projects.4 For instance,
many VOC users will be making switches to water-based or powder-
paint application systems as a strategy for meeting reasonably
available control technology (PACT) or switching to a non-toxic
VOC to comply with maximum achievable control technology (MACT)
requirements.
Accordingly, under today's guidance, permitting authorities
may consider excluding raw material substitutions, process
changes and other pollution prevention strategies where the
pollution control aspects of the project are clearly evident and
will result in substantial emissions reductions per unit of
output for one or more pollutants. In judging whether a
pollution prevention project can be considered for exclusion as a
pollution control project, permitting authorities may also
consider as a relevant factor whether a project is being
undertaken to bring a source into compliance with a MACT, RACT,
or other Act requirement.
Although EPA is supportive of pollution control and
prevention projects and strategies, special care must be taken in
classifying a project as a pollution control project and in
evaluating a project under a pollution control project exclusion.
Virtually every modernization or upgrade project at an existing
industrial facility which reduces inputs and lowers unit costs
has the concurrent effect of lowering an emissions rate per unit
of fuel, raw material or output. Nevertheless, it is clear that
these major capital investments in industrial equipment are the
very types of projects that Congress intended to address in the
new source modification provisions [see Wisconsin Electric Power
Co. v. Reillv. 893 F.2d 901, 907-10 (7th Cir. 1990) (rejecting
contention that utility life extension project was not a physical
or operational change); Puerto Rican Cement Co.. Inc. v. EPAf 889
F.2d 292, 296-98 (1st Cir. 1989) (NSR applies to modernization
project that decreases emissions per unit of output, but
increases economic efficiency such that utilization may increase
and result in net increase in actual emissions) ]. Likewise, the
replacement of an existing emissions unit with a newer or
different one (albeit more efficient and less polluting) or the
4For purposes of this guidance, pollution prevention means
any activity that through process changes, product reformulation
or redesign, or substitution of less polluting raw materials,
eliminates or reduces the release of air pollutants and other
pollutants to the environment (including fugitive emissions)
prior to recycling, treatment, or disposal; it does not mean
recycling (other than certain "in-process recycling" practices) ,
energy recovery, treatment, or disposal [see Pollution Prevention
Act of 1990 section 6602(b) and section 6603 (5) (A) and (B) ; see
also "EPA Definition of 'Pollution Prevention,'" memorandum from
F. Henry Habicht II, May 28, 1992].
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reconstruction of an existing emissions unit would not qualify as
a pollution control project. Adopting a policy that
automatically excludes from NSR any project that, while lowering
operating costs or improving performance, coincidentally lowers a
unit's emissions rate, would improperly exclude almost all
jnodifications to existing emissions units, including those that
ane likely to increase utilization and therefore result in
overall higher levels of emissions.
In order to limit this exclusion to the subset of pollution
prevention projects that will in fact lower annual emissions at a
source, permitting authorities should not exclude as pollution
control projects any pollution prevention project that can be
reasonably expected to result in an increase in the utilization
of the affected emissions unit(s). For example, p'rojects which
significantly increase capacity, decrease production costs, or
improve product marketability can be expected to affect
utilization patterns. With these changes, the environment may or
may not see a reduction in overall source emissions; it depends
on the source's operations after the change, which cannot be
predicted with any certainty.5 This is not to say that these
types of projects are necessarily subject to major NSR
requirements, only that they should not be excluded as pollution
control projects under this guidance. The EPA may consider
different approaches to excluding pollution prevention projects
from major NSR requirements in the upcoming NSR rulemaking.
Under this guidance, however, permitting authorities should
carefully review proposed pollution prevention projects to
evaluate whether utilization of the source will increase as a
result of the project.
Furthermore, permitting authorities should have the
authority to monitor utilization of an affected emissions unit or
source for a reasonable period of time subsequent to the project
to verify what effect, if any, the project has on utilization.
In cases where the project has clearly caused an increase in
utilization, the permitting authority may need to reevaluate the
basis for the original exclusion to verify that an exclusion is
still appropriate and to ensure that all applicable safeguards
are being met.
5This is in marked contrast to the addition of pollution
control equipment which typically does not, in EPA's experience,
result in any increase in the source's utilization of the
emission unit in question. In the few instances where this
presumption is not true, the safeguards discussed in the next
section should provide adequate environmental protections for
these additions of pollution control equipment.
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B. Safeguards
The following safeguards are necessary to assure that
projects being considered for an exclusion qualify as
environmentally beneficial pollution control projects and do not
iiave air quality impacts which would preclude the exclusion.
Consequently, a project that does not meet these safeguards does
not qualify for an exclusion under this policy.
1. Environmentally-Beneficial Test
Projects that meet the definition of a pollution control
project outlined above may nonetheless cause collateral emissions
increases or have other adverse impacts. For instance, a large
VOC incinerator, while substantially eliminating VOC emissions,
may generate sizeable NO, emissions well in excess of
significance levels. To protect against these sorts of problems,
EPA in the WEPCO rule provided for an assessment of the overall
environmental impact of a project and the specific impact, if
any, on air quality. The EPA believes that this safeguard is
appropriate in this policy as well.
Unless information regarding a specific case indicates
otherwise, the types of pollution control projects listed in
III. A. 1. above can be presumed, by their nature, to be
environmentally beneficial. This presumption arises from EPA's
experience that historically these are the .very types of
pollution controls applied to new and modified emissions units.
The presumption does not apply, however, where there is reason to
believe that 1) the controls will not be designed, operated or
maintained in a manner consistent with standard and reasonable
practices; or 2) collateral emissions increases have not been
adequately addressed as discussed below.
In making a determination as to whether a project is
environmentally beneficial, the permitting authority must
consider the types and quantity of air pollutants emitted before
and after the project, as well as other relevant environmental
factors. While because of the case-by-case nature of projects
it is not possible to list all factors which should be considered
in any particular case, several concerns can be noted.
First, pollution control projects which result in an
increase in non-targeted pollutants should be reviewed to
determine that the collateral increase has been minimized and
will not result in environmental harm. Minimization here does
not mean that the permitting agency should conduct a BACT-type
review or necessarily prescribe add-on control equipment to
treat the collateral increase. Rather, minimization means that,
within the physical configuration and operational standards
usually associated with such a control device or strategy, the
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source has taken reasonable measures to keep any collateral
increase to a minimum. For instance, the permitting authority
could require that a low-NOx burner project be subject to
temperature and other appropriate combustion standards so that
carbon monoxide (CO) emissions are kept to a minimum, but would
^not review the project for a CO catalyst or other add-on type
options. In addition, a State's RACT or MACT rule may have
explicitly considered measures for minimizing a collateral
increase for a class or category of pollution control projects
and requires a standard of best practices to minimize such
collateral increases. In such cases, the need to minimize
collateral increase from the covered class or category of
pollution control projects can be presumed to have been
adequately addressed in the rule.
In addition, a project which would result in an unacceptable
increased risk due to the release of air toxics should not be
considered environmentally beneficial. It is EPA's experience,
however, that most projects undertaken to reduce emissions,
especially add-on controls and fuel switches, result in
concurrent reductions in air toxics. The EPA expects that many
pollution control projects seeking an exclusion under this
guidance will be for the purpose of complying with MACT
requirements for reductions in air toxics. Consequently, unless
there is reason to believe otherwise, permitting agencies may
presume that such projects by their nature will result in reduced
risks from air toxics.
2. Additional Air Quality Impacts Assessments
(a) General
Nothing in the Act or EPA's implementing regulations would
allow a permitting authority to approve a pollution control
project resulting in an emissions increase that would cause or
contribute to a violation of a NAAQS or PSD increment, or
adversely impact visibility or other AQRV in a class I area [see,
e.g., Act sections 110(a)(2)(C), 165, 169A(b), 173].
Accordingly, this guidance is not intended to allow any project
to violate any of these air quality standards.
As discussed above, it is possible that a pollution control
project—either through an increase in an emissions rate of a
collateral pollutant or through a change in utilization—will
cause an increase in actual emissions, which in turn could cause
or. contribute to a violation of a NAAQS or increment or
adversely impact AQRV's. For this reason, in the WEPCO rule the
EPA required sources to address whenever 1) the proposed change
would result in a significant net increase in actual emissions of
any criteria pollutant over levels used for that source in the
most recent air quality impact analysis; and 2) the permitting
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authority has reason to believe that such an increase would cause
or contribute to a violation of a NAAQS, increment or visibility
limitation. If an air quality impact analysis indicates that the
increase in emissions will cause or contribute to a violation of
any ambient standard, PSD increment, or AQRV, the pollution
.control exclusion does not apply.
*
The EPA believes that this safeguard needs to be applied
here as well. Thus, where a pollution control project will
result in a significant increase in emissions and that increased
level has not been previously analyzed for its air quality impact
and raises the possibility of a NAAQS, increment, or AQRV
violation, the permitting authority is to require the source to
provide an air quality analysis sufficient to demonstrate the
impact of the project. The EPA will not necessarily require that
the increase be modeled, but the source must provide sufficient
data to satisfy the permitting authority that the new levels of
emissions will not cause a NAAQS or increment violation and will
not adversely impact the AQRV's of nearby potentially affected
class i areas.
In the case of nonattainment areas, the State or the source
must provide offsetting emissions reductions for any significant
increase in a nonattainment pollutant from the pollution control
project. In other words, if a significant collateral increase of
a nonattainment pollutant resulting from a pollution control
project is not offset on at least a one-to-one ratio then the
pollution control project would not qualify as environmentally
beneficial.6 However, rather than having to apply offsets on a
case-by-case basis, States may consider adopting (as part of
their attainment plans) specific control measures or strategies
for the purpose of generating offsets to mitigate the projected
collateral emissions increases from a class or category of
pollution control projects.
(b) Determination of Increase in Emissions
The question of whether a proposed project will result in an
emissions increase over pre-modification levels of actual
emissions is both complicated and contentious. It is a question
that has been debated by the New Source Review Reform
Subcommittee of the Clean Air Act Advisory Committee and is :
expected to be revisited by EPA in the same upcoming rulemaking
that will consider adopting a pollution control project
exclusion. In the interim, EPA is adopting a simplified approach
6Regardless of the severity of the classification of the
nonattainment area, a one-to-one offset ratio will be considered
sufficient under this policy to mitigate a collateral increase
from a pollution control project. States may, however, require
offset ratios that are greater than one-to-one.
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to determining whether a pollution control project will result in
increased emissions.
The approach in this policy is premised on the fact that EPA
does not expect the vast majority of these pollution control
projects to change established utilization patterns at the
source. As discussed in the previous section, it is EPA's
experience that add-on controls do not impact utilization, and
pollution prevention projects that could increase utilization may
not be excluded under this guidance. Therefore, in most cases it
will be very easy to calculate the emissions after the change:
the product of the new emissions rate times the existing
utilization rate. In the case of a pollution control project
that collaterally increases a non-targeted pollutant, the actual
increase (calculated using the new emissions rate "and current
utilization pattern) would need to be analyzed to determine its
air quality impact.
The permitting authority may presume that projects meeting
the definition outlined in section III(A)(1) will not change
utilization patterns. However, the permitting authority is to
reject this presumption where there is reason to believe that the
project will result in debottlenecking, loadshifting to take
advantage of the control equipment, or other meaningful increase
in the use of the unit above current levels. Where the project
will increase utilization and emissions, the associated emissions
Increases are calculated based on the post-modification potential
to emit of the unit considering the application of the proposed
controls; In such cases the permitting agency should consider
the projected increase in emissions as collateral to the project
and determine whether, notwithstanding the emissions increases,
the project is still environmentally beneficial and meets all
applicable safeguards. ^ ,
In certain limited circumstances, a permitting agency may
take action to impose federally-enforceable limits on the
magnitude of a projected collateral emissions increase to ensure
that all safeguards are met. For example, where the data used to
assess a projected collateral emissions increase is questionable
and there is reason to believe that emissions in excess of the
projected increase would violate an applicable air quality
standard or significantly exceed the quantity of offsets
provided, restrictions on the magnitude of the collateral
increase may be necessary to ensure compliance with the
applicable safeguards.
IV. Procedural Safeguards
Because EPA has not yet promulgated regulations governing a
generally applicable pollution control project exclusion from
major NSR (other than for electric utilities), permitting
authorities must consider and approve requests for an exclusion
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on a case-by-case basis, and the exclusion is not self-executing.
Instead, sources must receive case-by-case approval from the
permitting authority pursuant to a minor NSR permitting process,
State nonapplicability determination or similar process.
[Nothing in this guidance voids or creates an exclusion from any
applicable minor source preconstruction review requirement in any
SIP that has been approved pursuant to section 110(a) (2) (C) and
40 CFR 51.160-164.] This process should also provide that the
application for the exclusion and the permitting agency's
proposed decision thereon be subject to public notice and the
opportunity for public and EPA written comment. In those limited
cases where the applicable SIP already exempts a class or
category of pollution controls project from the minor source
permitting public notice and comment requirementst and where no
collateral increases are expected (e.g., the installation of a
baghouse) and all otherwise applicable environmental safeguards
are complied with, public notice and comment need not be provided
for such projects. However, even in such circumstances, the
permitting agency should provide advance notice to EPA when it
applies this policy to provide an exclusion. For standard-wide
applications to groups of sources (e.g., RACT or MACT), the
notice may be provided to EPA at the time the permitting
authority intends to issue a pollution control exclusion for the
class or category of sources and thereafter notice need not be
given to EPA on an individual basis for sources within the
noticed group.
V. Emission Reduction Credits
In general, certain pollution control projects which have
been approved for an exclusion from major NSR may result in
emission reductions which can serve as NSR offsets or netting
credits. All or part of the emission reductions equal to the
difference between the pre-modification actual and post-
modification potential emissions for the decreased pollutant may
serve as credits provided that 1) the project will not result in
a significant collateral increase in actual emissions of any
criteria pollutant, 2) the project is still considered
environmentally beneficial, and 3) all otherwise applicable
criteria for the crediting of such reductions are met (e.g.,
quantifiable, surplus, permanent, and enforceable). Where an
excluded pollution control project results in a significant :
collateral increase of a criteria pollutant, emissions reduction
credits from the pollution control project for the controlled
pollutant may still be granted provided, in addition to 2) and 3)
above, the actual collateral increase is reduced below the
applicable significance level, either through contemporaneous
reductions at the source or external offsets. However, neither
the exclusion from major NSR nor any credit (full or partial) for
emission reductions should be granted by the permitting authority
where the type or amount of the emissions increase which would
result from the use of such credits would lessen the
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environmental benefit associated with the pollution control
project to the point where the project would not have initially
qualified for an exclusion.
IV. illustrative Examples
The following examples illustrate some of the guiding
principles and safeguards discussed above in reviewing proposed
pollution control projects for an exclusion from major NSR.
Example 1
PROJECT DESCRIPTION: A chemical manufacturing facility in
an attainment area for all pollutants is proposing to install a
. RTO to reduce VOC emissions (including emissions of some
hazardous pollutants) at the plant by about 3000 tons per year
(tpy). The emissions reductions from the RTO are currently
voluntary, but may be necessary in the future for title III MACT
compliance. Although the RTO has been designed to minimize NOX
emissions, it will produce 200 tpy of new NO, emissions due to
the unique composition of the emissions stream. There is no •
information about the project to rebut a presumption that the
project will not change utilization of the source. Aside from
the NOX increase there are no other environmental impacts known
to be associated with the project.
EVALUATION: As a qualifying add-on control device, the
project may be considered a pollution control project and may be
considered for an exclusion. The permitting agency should:
1) verify that the NOX increase has been minimized to the extent
practicable, 2) confirm (through modeling or other appropriate
means) that the actual significant increase in NOX emissions does
not violate the applicable NAAQS,7 PSD increment, or adversely
impact any Class I area AQRV, and 3) apply all otherwise
applicable SIP and minor source permitting requirements,
including opportunity for public notice and comment.
Example 2
PROJECT DESCRIPTION: A source proposes to replace an
existing coal-fired boiler with a gas-fired turbine as part of a
cogeneration project. The new turbine is an exact replacement
for the energy needs supplied by the existing boiler and will
emit less of each pollutant on an hourly basis than the boiler
did.
7If the source were located in an area in which
nonattainment NSR applied to NOX emissions increases, 200
tons of NOX offset credits would be required for the project
to be eligible for an exclusion.
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EVALUATION: The replacement of an existing emissions unit
with a new unit (albeit more efficient and less polluting) does
not qualify for an exclusion as a pollution control project. The
company can, however, use. any otherwise applicable netting
credits from the removal of the existing boiler to seek to net
the new unit out of major NSR.
Example 3
PROJECT DESCRIPTION: A source plans to physically renovate
and upgrade an existing process line by making certain changes to
the existing process, including extensive modifications to
emissions units. Following the changes, the source will expand
production and manufacture and market a new product line. The
project will cause an increase in the economic efficiency of the
line. The renovated line will also be less polluting on a per-
product basis than the original configuration.
EVALUATION: The change is not eligible for an exclusion as
a pollution control project. On balance, the project does not
have clearly evident pollution control aspects, and the resultant
decrease in the per-prbduct emissions rate (or factor) is
incidental to the project. The project is a physical change or
change in the method of operation that will increase efficiency
and productivity.
Example 4
PROJECT DESCRIPTION: In response to the phaseout of
chlorofluorocarbons (CFC) under title VI of the Act, a major
source is proposing to substitute a less ozone-depleting
substance (e.g., HCFC-141b) for one it currently uses that has a
greater ozone depleting potential (e.g., CFC-11) . A larger
amount of the less-ozone depleting substance will have to be
used. No other changes are proposed.
EVALUATION: The project may be considered a pollution
control project and may be considered for an exclusion. The
permitting agency should verify that 1) actual annual emissions
of HCFC-141b after the proposed switch will cause less
stratospheric ozone depletion than current annual emissions of
CFC-ll; 2) the proposed switch will not change utilization
patterns or increase emissions of any other pollutant which would
impact a NAAQS, PSD increment, or AQRV and will not cause any
cross-media harm, including any unacceptable increased risk
associated with toxic air pollutants; and 3) apply all otherwise
applicable SIP and minor source permitting requirements,
including opportunity for public notice and comment.
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Example 5
PROJECT DESCRIPTION: An existing landfill proposes to
install either flares or energy recovery equipment [i.e.,
turbines or internal combustion (1C) engines]. The reductions
-from the project are estimated at over 1000 tpy of VOC and are
currently not necessary to meet Act requirements, but may be
necessary some time in the future. In case A the project is the
replacement of an existing flare or energy system and no increase
in NO, emissions will occur. In case B, the equipment is a first
time installation and will result in a 100 tpy increase in NOX.
In case C, the equipment is an addition to existing equipment
which will accommodate additional landfill gas (resulting from
increased gas generation and/or capture consistent with the
current permitted limits for growth at the landfill) and will
result in a 50 tpy increase in NOX.
EVALUATION: Projects A, B, and C may be considered
pollution control projects and may be considered for an
exclusion; however, in cases B and C, if the landfill is located
in an area required to satisfy nonattainment NSR for NOX
emissions, the source would be required to obtain NOX offsets at
a ratio of at least 1:1 for the project to be considered for an
exclusion. [NOTE: VOC-NOX netting and trading for NSR purposes
may be discussed in the upcoming NSR rulemaking, but it is beyond
the scope of this guidance.] Although neither turbines or 1C
engines are listed in section III.A.I as addron control devices
and would normally not be considered pollution control projects,
in this specific application they serve the same function as a
flare, namely to reduce VOC emissions at the landfill with the
added incidental benefit of producing useful energy in the
process.8
The permitting agency should: 1) verify that the NOX
increase has been minimized to the extent practicable; 2) confirm
(through modeling or other appropriate means) that the actual
significant increase in NOX emissions will not violate the
8The production of energy here is incidental to the project
and is not a factor in qualifying the project for an exclusion as
a pollution control project. In addition, any supplemental or
co-firing of non-landfill gas fuels (e.g., natural gas, oil)
would disqualify the project from being considered a pollution
control project. The fuels would be used to maximize any
economic benefit from the project and not for the purpose of
pollution control at the landfill. However, the use of an
alternative fuel solely as a backup fuel to be used only during
brief and infrequent start-up or emergency situations would not
necessarily disqualify an energy recovery project from being
considered a pollution control project.
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applicable NAAQS, PSD increment, or adversely impact any AQRV;
and 3) apply all otherwise applicable SIP and minor source and,
as noted above, in cases B and C ensures that NOX offsets are
provided in an area in which nonattainment review applies to NO
emissions increases, permitting requirements, including
opportunity for public notice and comment.
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APPENDIX L: ALTERNATIVE ENERGY & REGULATORY POLICY: TILL DEATH DO WE PART (Presentation)
Frank P. Wong
Pacific Energy
6055 East Washington Boulevard
Commerce, California 90040
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ALTERNATIVE ENERGY & REGULATORY POLICY:
TILL DEATH Do WE PART
FRANK P. WONG
PACIFIC ENERGY
6055 EAST WASHINGTON BLVD.
COMMERCE, CA 90040
MARCH 18,1992
ABSTRACT
This paper provides a non-technical and top-sided discussion of the historic
relationship between the alternative energy industry in general and Pacific Energy's
landfill gas recovery business experience in particular with regulatory policies effecting
the same. Included is a discussion of the evolution from early encouragement of the
industry to more recent ambivalence toward the relationship. Industry has no option but
to adapt to the realities of today's environment. Regulatory policy makers, on the other
hand, must learn to recognize the potentially chilling long-term impact their decisions
have on business. Both parties can optimize their respective positions to the public's
benefit by working together to draft practical and meaningful regulations that address
legitimate public concerns.
INTRODUCTION
Pacific Energy (PEn) is a major developer of alternative energy projects in the
under 50 megawatt (MW) size range. It began its history as a developer and operator of
district heating and cooling plants in the L.A.-Orange County area in 1963. PEn's
diversification into alternative energy development began in 1980 directly in response to
the Public Utilities Regulatory Policy Act (PURPA) of 1978. To-date it has been
involved in the development of twenty-five alternative energy projects designed to
produce over 170 MW of electric power.
Because of the legislated origin of the industry, there has always been a symbiotic
relationship between public policy and the alternative energy industry. Public policy
makers have expected and received much from the industry. However, over the past
dozen years, PEn has been both witness and participant in dramatic changes involving
public regulatory policy effecting the industry.
For example, growing public awareness and environmental concerns surrounding
landfills, coupled with changes in economic incentives have changed the character of
landfill gas recovery. This has required companies like PEn to adapt to such changes
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despite the fact not a single dollar in added cost can be past through to the utility
purchasing the generated electricity.
PEn believes there continues to be great opportunity for the alternative energy
industiy, in particular landfill gas recover)', to complement public regulatory policy. The
key to optimizing private industry participation in the development of practical rule
making is open communication and flexible attitudes on all sides.
DISCUSSION
Historical Perspective
They say "opposites attract and the best marriages are those in which the parties
complement each other." They also say, "can't live with 'em...can't live without 'em."
Those two phrases seem to sum up the often love-hate relationship that exists between
regulatory policy and private industry in general and is equally applicable to the
alternative energy industry.
.In reflecting upon the historic relationship between regulatory policy and the
alternative energy industry, it is significant to remember that the alternative energy
industry owes its existence to regulatory policy. It was Congress in 1978 that passed the
Public Utilities Regulatory Policy Act, commonly referred to as PURPA, that defined the
alternative energy industry. It was the Supreme Court that upheld PURPA against
vigorous challenges by utilities, which opened the door for qualified facilities into the
previously exclusive utilities-only electric generation club. It was the public utilities
commissions and other state support that helped level the playing field by penalizing
some utilities for obstructing alternative energy development and pioneering such things
as fmancable standard offer contracts. It was Congress again that helped the alternative
energy industry afford the price of admission by providing tax incentives that provided
the incremental difference to encourage capital investment in general and alternative
energy development in particular.
During this phase of the relationship, which can be referred to as the Courtship
Phase, regulatory policy makers, of course, had compelling reasons for such largess.
OPEC had taken over from the Texas Railroad Commission as the dominate power in
setting world oil supply and hence prices; constituents were waiting in gasoline lines —
for a second time within the decade; oil prices had increased from S6-8 per barrel to S35
per barrel in the span of a decade with consensus forecasts of continued real price
escalation; many utilities were economically and philosophically committed to building
huge central power stations requiring 10 or more years to plan and construct to meet
future capacity requirements, and embroiled in a nuclear construction program
characterized by ever-escalating cost overruns and little public support.
Encouraged by these tax and regulatory incentives, private industry responded
with a passion. The result has been a permanent change in the character of the power
market. Demand for energy has not decreased but the diversity of supply has
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dramatically increased. California, in fact, has reduced its utility use of oil since 1976 by
90% (IEP, 1991). OPEC, white still a factor, no longer controls world oil prices; and but
for new taxes, the price of gasoline is less today than it was a few years ago. Privately
developed "qualified facilities" make new generating capacity available to utilities in
substantially less time and in more flexible increments than the best nuclear power plant
and rate payers take no development risk. Recently, for example, Boston Edison
requested bids for 132 MW of new capacity. In response, it received 40 bids for 3000
MTW of capacity (Independent Power Report, February 28, 1992).
All-in-all, an apparent marriage made in heaven. But unlike "Beauty and the
Beast," this story doesn't just end. As in real life, the wedding is just the beginning. As
the parties learn to live with each other, each starts the relationship intending to support
the other in a way that allows both to actualize their own respective needs and live
happily ever after. However, life doesn't often follow according to plan.
Pacific Energy
PEn is one of the many firms that entered into the alternative energy business
with an entrepreneurial attitude in the late 1970's and early 1980's. We have enough
arrows in our corporate back to believe we qualify as one of the pioneers in this industry.
. PEn was formally established in 1982 after two years of development under the
auspices of its predecessor company, Central Plants, Inc., to pursue its parent company's
(Pacific Enterprises, S6.6 billion, NYSE) interest in the development and operation of
alternative energy projects, including projects that produce electric power using resources
such as landfill gas, wastewood, geothermal hot water, and hydropower. To-date, PEn
has been involved in the development of 25 alternative energy projects designed to
produce over 170 megawatts of electric power. Within the last two years, PEn has
completed one new hydropower project, two new geothermal projects, and two landfill
gas project expansions.
PEn Landfill Development
PEn, for one, believes the relationship between regulatory policy and alternative
energy has worked well for the public interest PEn's landfill gas recovery projects, in
particular, have successfully provided many of the benefits envisioned by the supporters
of alternative energy plus many uncounted public benefits that go beyond PURPA.
While landfill gas resources are individually small, collectively they can be
significant. PEn, as a single company, has developed twelve electric generating facilities
utilizing landfill gas from seventeen different landfills. Four of these projects have been
shut down for economic reasons and the eight facilities operating today represent over 30
MW of landfill gas fueled generating resources. All but one of these projects are located
in California with one located in Maryland The benefits of this modest development
alone include:
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Conservation of nation's fossil fuel resources. PEn's 30 MW's of landfill gas
recovery is enough to meet the demand of roughly 30,000 homes with an
otherwise wasted and unwanted resource.
Reduced dependence on imported oil. The 30 MW developed by PEn is
equivalent to over 500,000 barrels of imported oil per year which is equivalent to
avoiding 10 million barrels of imported oil over (he forecasted 20 year project
life.
Reduced balance of trade deficit. At an average price of $20 per barrel, this
represents a savings of S10 million per year.
Offset higher polluting utility generation. Alternative energy typically offsets the
utilities' older, least efficient and most polluting central power stations (California
Energy Markets, January 3, 1992). Pacific Gas & Electric's incremental energy
rate in the early 1980's was over 16,000 BTU per kwh. Today, it is less than
10,000 BTU per kwh because of low demand from its older, least efficient fossil
fuel plants.
Mitigation of greenhouse effect. An independent study concluded that landfill
gas power plants,' when comparing the net environmental impact with other
sources of energy (oil, coal, natural gas, cogeneration, wastewood, geothermal,
solar, and wind), actually help to reduce the overall greenhouse effect by
converting the methane gas produced in landfills to carbon dioxide (Gleick, et al,
1989). Methane is a 25 times more potent greenhouse gas compared to carbon
dioxide.
Mitigation of landfill gas migration._ernissions and odors. Collection of landfill
gas for power generation reduces the likelihood of underground lateral migration
that can create a safety hazard; and reduce surface emissions that can create odor
nuisances, health concerns and deterioration of air quality. PEn's eight projects
can collect and safely combust approximately 20 million standard cubic feet of
landfill gas per day.
Substantial cost savings to public entities owning landfill. All but one of PEn's
landfill gas recover}' projects are on publicly owned landfills. PEn's operation
can often eliminate or at least substantially reduce the landfill owner's need for a
landfill gas migration control and flare system. The cost for a collection and flare
system is usually on the order of several hundred thousand to over a million
dollars per landfill, plus ongoing expenses to operate and maintain it and meet
applicable health and safety regulations.
Royalty payments to public entities. On average, PEn's projects are in the sixth
year of operation under anticipated twenty year project lives. As of the end of
last year, PEn has paid out S13 million in royalty payments, mostly to public
entities.
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• Higher .property basis. Privateiy developed landfill gas recovery projects are
capital intensive and typically built on otherwise undevelopable acreage. PEn's
eight landfill projects pay over S350,000 per year in property taxes in California
and demand little by way of public services.
• Purchase of goods and services. In 1991, PEn purchased over S4 million in
outside goods and services to support its landfill gas recovery operations plus had
a direct payroll of over S3 million.
In short, PEn's landfill gas projects have provided an economic and.
environmental benefit to the local community as well as the nation. These projects have
. proven the feasibility of landfill gas recovery that can be replicated across the United
States with the proper economic incentives. Yet, of the estimated 6500 plus landfills in
the U.S., less than 200 have energy recovery systems (Berenyi and Gould, 1991)
primarily as a result of lower energy prices, reduced tax incentives, and increasing
environmental liability.
Citing PEn's landfill gas recovery development history as an example, it should
appear obvious that there is much to gain on both sides through cooperative efforts. In
general, the alternative energy industry has largely provided what the public policy
makers during the times of the Middle East oil crisis asked of it. Billions of dollars have
been invested and billions more will be needed to meet growing energy demands. It has
been shown development can be done in an environmentally safe manner that can not
only shield the public from economic risk but also provide direct and indirect economic
and social benefits as well.
Today, however, the regulatory climate is much different and I am reminded of
the suggestions Cogsworth gives to the Beast to court Beauty early in the movie when
recommending the "usual gifts: candies, flowers, promises you don't intend to keep..."
As implied in the last suggestion, there comes a time when each party must determine its
commitment to the relationship. With the demand and price of oil at least temporarily in
control; tax incentives a thing of the past; and public utilities, with the blessing of PUC's,
taking aggressive positions to the detriment of alternative energy, some might say the
honeymoon is over.
Add to this list the fact that environmental regulations are expanding in scope at
an ever increasing rate and their related compliance costs are escalating at an accelerating
pace well beyond both inflation and original financial forecasts. In California alone,
there was forty-eight different pieces of state legislation effecting solid waste which were
enacted last year, or almost one per week (SWANA, 1992). Typically, the air districts
want it regulated out of the atmosphere, the water pollution agencies want it regulated
out of liquid disposal, and the solid waste agencies don't want it either. There has been
little, if any, coordination of priorities nor credit given to net overall environmental, let
alone environmental and economic, benefits. Not surprisingly, there are many in the
alternative energy industry that feel regulatory policy makers have abandoned this
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relationship and arc reluctant to pursue this beneficial energy resource because of the
perceived regulatory risks.
Dealing With Changes
In defense of such regulator)' policy, I remind others in my industry that it is the
same public policy concern for the greater good that created PURPA over the objections
of almost every major utility in the country. This same concern for the greater good is
also mandating the current changes. Like it or not, regulations are going to be developed
and implemented with or without the help of private industry. The goal of industry
should therefore he not to thwart regulations but to provide the necessary technical _
expertise, information and insight required to create practical and meaningful regulations.
PEn's approach to dealing with regulatory uncertainty has evolved over the past
several years. After starting up all twelve of our landfill projects in a period between
1984 and 1986, we spent the first few years internally focused and working through
startup problems. This is the period I referred to earlier as having to remove a few
arrows from our corporate back.
During this post honeymoon transition period, we have had over 100% turnover
in some departments, shut down four landfill gas recovery projects, and restructured
several partnerships involved in the ownership of the projects. We have cut expenses as
well as improved operations by internalizing more of our maintenance versus relying on
outside contractors. We have worked closely with landfill owners and operators on a
give-and-take basis addressing their concerns and balancing them with our own needs for
financial integrity.
Partly as a result of this experience, we have developed a great appreciation for
maintaining an open, flexible, and practical approach to problem solving. And while the
current and ongoing evolution in regulatory policies is no less disconcerting to PEn than
to any other company, we have concluded the obvious, that the best way to deal with the
inevitable changes is to become involved in the development process. A well thought out
regulation that takes into account the practical experience of industry experts is vastly
superior to poorly drafted text book regulations that develop in a vacuum of data.
Therefore, recognizing landfill gas management is a relatively narrow field of
expertise that represents a major public concern, PEn has begun a program to actively
work with regulatory agencies in its field to avail them of PEn's experience. This has
included providing specific comments to proposed landfill gas regulations, acting as site
host, for a U.S. Environmental Protection Agency (EPA) landfill gas fuel cell
demonstration program, providing original research, active participation in various
industry organization, and simply meeting with various regulatory agencies to ask them
questions on current and future priorities and providing them with relevant information
as appropriate. Also, because we have been dissatisfied with the landfill gas
'management techniques in common use, we developed new landfill gas management
tools which we propose to share with others in the landfill gas industry.
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Among the landfill gas management techniques PEn has promoted are:
• Standardization of operating procedures.
• Better training of operating and regulatory personnel in understanding landfill gas
dynamics.
• Use of higher quality data in gas management decision making.
• Integrated systems approach to landfill gas management.
• Development of objective regulations that do not penalize landfill owners that
demonstrate a good faith compliance effort.
Public-Private Partnership
Public policy makers, on the other hand, must recognize there must be mutual
benefit for a relationship to prosper. Much has been said about Japanese management
techniques and how U.S. companies can leam from them. Among the enviable
characteristics that seem to distinguish Japan's long term business strategy approach is
the partnership between government and business. The reassuring aspect of this joint
goals setting approach for business is that it eliminates surprises from its most vital
partner.
Regulatory policy makers must recognize that alternative energy projects are
typically captive producers; meaning unlike most businesses, once a project is
constructed, it does not have the freedom to change its customer nor vary its prices. The
options they do have are shutting down projects, diversifying out of alternative energy,
and being extremely selective on new capital investments. Billions of dollars of
investment have been committed by the alternative energy industry under prior and
existing policies and their future success is knotted with on-going regulatory policy. To
a large degree, public policy is determining what projects will be built, what they will be
paid, and what it will cost them to operate.
When PEn evaluates a prospective project, its analysis is relatively straight
forward. It considers the resource and technology, reviews the environmental and
permitting issues, confirms the financing options, estimates the income and expenses, and
most importantly evaluates the predictability of all the above. If private industry
concludes it cannot trust in a consistent regulatory policy, it loses its ability to plan and
hence its ability to make long term commitments.
Current power plant siting criteria almost assures natural gas will be the fuel of
choice, never mind the long term benefits of conserving this clean burning domestic fuel
resource for future generations. In California, the CPUC is becoming the dominant force
in setting contract administration policy between the utilities and alternative energy
power producers even though they are not a signature to the contract. PEn now has a
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separate environmental staff of five people, not counting legal and engineering support,
and the landfill gas group alone spent S0.5 million in 1991 on testing and compliance.
PEn is not considering relocating its alternative energy projects -- but only
because it can't. PEn is therefore committed to working together toward a long and
prosperous relationship. Like a marriage without divorce, we are comrrutted to making
this relationship work, till death do we part.
CONCLUSION
The history and future of the alternative energy industry is intertwined, for better
or for worse, with public policy. Given that change is inevitable, both sides must learn to
be flexible and work cooperatively together in planning our future energy mix. Parochial
views and short sighted policies will cripple the future of this industry and risk the
substantial gains realized thus far. Alternative energy projects do not have the option of
relocating once their investment is made. The options they do have include shutting
down projects, diversifying out of alternative energy, being very selective on new capital
investments, and working with regulatory policy makers.
Regulatory policy makers must realize there is no free lunch. If private industry
concludes it cannot trust in a consistent regulatory policy based on a coordinated set of
priorities, it will perceive the uncertainties and lose its ability to plan. Without such an
ability to plan, it cannot make long term commitments. Without long term commitments,
there are no projects — no benefits -- no future relationship. PEn, however, believes that
despite the often differing goals between regulatory policy and private industry, it has
been demonstrated that our efforts can be combined and cooperative for the benefit of the
nation now and in the future.
REFERENCES
Journal Article
1. "Boston Edison Gets 40 Bids Totaling 3,000 MW In Response To 132-MW
RFP." Independent Power Report. February 28, 1992.
2. A. O'Donnell, "Bottom Lines - A Question of Standards," California Energy,
Markets. No. 138, Pages 5-7, January 3, 1992.
Publications
1. J. Smutny-Jones, Alternative Energy Technologies Overview Fact Sheet.
Independent Energy Producers Association, 1991.
2. P. H. Gleick, G. P. Morris and N. A. Norman, Greenhouse Gas Emissions From
The Operation Of Energy Facilities. Independent Energy Producers Association,
July 22, 1989.
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E. Bercnyi and R_ Gould, 1991 - 92 Methane Recovery From Landfill Yearbook.
Governmental Advisors'Associates, Inc., New York, NY, 1991.
4. List Of Solid Waste Legislation Enactedjn 1991. Solid Waste Association of
North America, Silver Springs, MD, 1992.
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APPENDIX M: RECENT DEVELOPMENTS, FUTURE PROSPECTS FOR SALES OF ELECTRICITY FROM
FACILITIES WHICH BURN LANDFILL GAS (Presentation)
Freddi L. Greenberg
Attorney at Law
1603 Orrington Avenue, Suite 1050
Evanston, Illinois 60201
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"RECENT DEVELOPMENTS, FUTURE PROSPECTS
FOR
SALES OF ELECTRICITY
FROM
FACILITIES WHICH BURN LANDFILL GAS"
.FREDDI L. GREENBERG
ATTORNEY
Good Morning. It's always a pleasure to attend SWANA's landfill
gas symposium and to see so many old friends. As you know, my
topic today is "Recent Developments and Future Prospects for Sales
of Electricity Generated Using Landfill Gas". I'm going to focus
on wholesale sales of electricity to utilities. The majority of
sales of electricity generated at landfill gas facilities are sales
to utilities.
You should be aware that you can also sell power at retail to a
consumer. Those sales generally are limited by the location of the
landfill. In the right situation, a retail sale should not be
overlooked. The landfill may be located adjacent to property which
could be developed for other purposes. An example might be an
industrial park. Another option is to sell the gas to a consumer.
Here again, project location can be a major limitation. The
heating value of landfill gas is another limiting factor. With a
retail sale of gas or electricity you should be aware the seller
might become regulated as a utility. This can create problems in
some states, but it has been done. Because so much is happening in
the area of sales to utilities, I will not discuss retail sales
further today. If any of you are interested in retail sales, I
will be glad to answer your questions later.
Let's take a look at the wholesale electric industry. It's been
almost 15 years since Congress passed a law called the Public
Utility Regulatory Policies Act or PURPA. One goal of PURPA was to
conserve fossil fuels by encouraging electric generation using
renewable fuels such as landfill gas. That goal has been met. As
result of PURPA, the electric utility industry has undergone a
revolutionary change. Before 1978, utilities generated almost all
the electricity consumed in the United States. The power was
generated by utility-owned plants which were part of a utility's
rate base. Today, there is a competitive market to supply
wholesale power to utilities. A utility no longer can be sure that
its state commission will allow it to construct a generating plant
when new capacity is needed. In many states, utilities must seek
competitive bids from a broad range of developers who may supply
capacity at a cost which is lower than if the utility built a new
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plant.
This means that there is tremendous opportunity for non-utility
generators - that includes you if you have a plant which burns
landfill gas. But competition among non-utility generators also
has increased. Price competition has led to lower payments to non-
utility generators. In addition, proposed laws and regulations may
erode the advantage that PURPA gave to landfill gas projects.
These opportunities and the threats to PURPA projects will be the
focus of my talk today.
I have divided my topic into four parts. I will begin with a
summary of the current laws and regulations which affect power
sales to utilities. I will then turn to the non-utility generating
industry. Where has it been, where is it going. What is the
marketplace like today? Third, I will discuss-new laws which are
likely to increase competition and reduce the PURPA advantage.
Fourth and last, I will talk about new trends which may allow the
landfill gas industry to compete effectively in the new
environment.
Let's begin by looking at PURPA. As you probably know, PURPA
guarantees a market for the electricity you generate. Utilities
are required to buy electricity generated by two general types of
facilities which qualify under PURPA. Qualifying cogeneration
facilities burn fossil fuels and must produce steam or heat along
with electricity. They are not limited in size, but must meet
certain efficiency standards. Qualifying small power producers
must use non-fossil technologies, such as solar, hydropower, wind,
waste and biomass.
To qualify under PURPA, your landfill gas plant must meet three
criteria. First, the fuel must qualify. Landfill gas is biomass
so fuel is not problem. In addition, a landfill gas facility may
burn up to 25 percent fossil fuel each year for limited purposes
such as startup, testing and flame stabilization. Second, a
utility or utility subsidiary may not own more than 50 percent of
a qualifying facility. Third, the facility's size is limited to 80
megawatts, though this limit has been temporarily lifted.
If your plant meets these criteria, it becomes a qualifying
facility or QF when you notify the Federal Energy Regulatory
Commission or FERC of the facility's status. There is no charge
for filing a notice. You may also ask the FERC to certify that the
facility qualifies. You should be aware that certification costs
several thousand dollars and does not give you any additional
benefits. Your lender may require certification as a condition of
financing the project. There also may be other reasons to certify
a facility.
I mentioned that utilities must buy power from QF's. A utility
must pay for QF power at the utility's avoided cost. Avoided cost
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is the cost to the utility if it did not purchase power from the QF
but generated the power itself or bought the power from another
supplier. The avoided cost may vary from one utility to
another.Sometimes avoided cost is seton a statewide basis. Avoided
costs of investor-owned utilities must be approved by the state
public utility commission. That approval is accomplished by means
of a regulatory proceeding with public participation.
Avoided cost has two components: energy and capacity. A utility
must buy energy from all qualifying facilities. The avoided energy
cost generally reflects the utility's fuel costs and operating and
maintenance expense. This number can be quite low, often well
below 2 cents a kilowatt hour.
When a utility needs capacity, its avoided cost includes a capacity
component. The capacity portion of avoided cost is based on the
next generating unit the utility intends to build. In theory, the
qualifying facility is compensated for the fact that its sale of
power will allow a utility to defer construction of the next
generating unit. If enough QF's are built, the utility may be able
to avoid building the generating unit.
In addition to a guaranteed market, PURPA gives two other benefits
to QF's. First, utilities must sell power to QF's at cost-based
rates. This is backup power which is needed when the QF isn't
operating. Backup power might be needed only to restart the
generator. The rate for backup power cannot discriminate against
QF's as compared to other utility customers. The rate for backup
power is important because it can include a demand component which
is payable monthly, whether or not backup power is purchased. The
demand charge may be set by the QF's highest annual usage.
Another important benefit of PURPA is that QF's are exempt from
utility regulation at the state and federal levels. This includes
regulation by the FERC, which regulates wholesale power sales. It
also includes rate regulation by state public utility commissions.
QF's are also exempt from regulation under the Public Utility
Holding Companies Act or PUHCA. PUHCA is administered by the
Securities and Exchange Commission. PUHCA regulation places a
significant burden on the parent company of the owner of an
electric generating facility. The prospect of PUHCA regulation has
been a major deterrent to developers of generating facilities which
do not qualify under PURPA. I will return to the topic of PUHCA
regulation a little later when I discuss pending legislation.
There is one benefit which PURPA does not give to QF's. That is
the right to require a utility to wheel or transmit power to
another utility. Utilities have always wheeled power for one
another". Some utilities also wheel power for QF's. But you can't
force a utility to wheel your power. This effectively limits the
market for your power to the utility which serves the area where
the QF is located.
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Let's turn now to my second topic: the non-utility generating
industry. As I mentioned, PURPA has revolutionized the industry by
creating competition to provide new capacity. In 1973, before
PURPA, about 4.3 percent of the electricity used in the United
States was generated by non-utilities.' In 1992 we know that 52
percent of the new baseload capacity needed by utilities will not
be generated by utilities. That 52 percent is actually a low
number because it does not include industrial cogeneration
facilities which also have multiplied since PURPA became law.
Today there are about 45,000 megawatts of non-utility generation
installed in the U.S. Another 60,000 megawatts are under
development. Development slowed a bit during 1991, but utilities
which need capacity have not found a shortage of developers
standing in line to meet that need. While the number of projects
is down from its peak, project *size is increasing. The average
size of installed non-utility plants is 12 megawatts. The average
size of all non-utility projects announced during 1991 was 96
megawatts.
Let's look at non-utility generation from a regional standpoint.
California has 10,000 megawatts in operation. Texas has about
7,000 megawatts. There has also been significant QF development in
the northeast and in Florida. Most of these QF's developed in
response to utility capacity needs where the avoided costs were
highest. The states which saw the greatest development of QF
capacity in 1991 were New York, New Jersey, Florida, California and
Massachusetts. During the next year, utilities in Texas,
California, Massachusetts, the Midwest and the Pacific northwest
are likely to require new capacity.
Many people believe that utilities all over the country will need
new capacity during the next ten years. Utilities may have
under forecast the need for new capacity. This is because utilities
have had problems in getting rate base treatment for their
generating facilities. Most planned utility plants are gas
turbines. One recent report questions whether the natural gas
industry can meet the delivery requirements of all these plants.
In addition, many utility plants are reaching the age of
retirement. Others may be shut down because they can't comply with
Clean Air Act requirements.
Utility need is only one part of the picture. Another important
development is the method used by utilities to meet that need. In
the early years of PURPA projects, utilities bought capacity from
QF's on a first come, first served basis. Today, the method of
choice for buying capacity is competitive bidding. The utility
issues a request for proposals or RFP. QF's that can provide the
needed "capacity bid against other potential suppliers. The
utility's avoided cost for a proposed generating unit is often the
benchmark or ceiling for the RFP. Some RFP's are open only to
QF's. A growing trend is "all-source" bidding in which all
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potential suppliers, and sometimes demand-management strategies,
compete to meet the utility's need.
To date, bidding has been used by utilities in 26 states. The
total number of RFP's to date is 90.At least 36 states have adopted
or are in the process of adopting competitive bidding programs.
Utility RFP's often are subject to approval of the state
commission. If you are interested in selling power to a particular
utility, it is a good idea to participate in any regulatory
proceeding which shapes the RFP.
Utilities which currently have RFP's open, or will in the near
future, include New England Power Company,Metropolitan Edison in
Pennsylvania, Pacific Power and Light in Washington State,
Indianapolis Power & Light, and Blue Ridge Power Authority. Non-
utility generators have traditionally looked to investor-owned
utilities as the market for power sales. It's time to look beyond
that market to public power. Municipal utilities, joint action
agencies and rural electrification co-operatives should be
considered. Joint action agencies purchase power on behalf of
groups of municipal utilities. In fact, AMP-Ohio is currently
seeking 100 megawatts.
Consider a non-generating municipal utility which buys all of its
power from one investor-owned utility. Generally, the full
requirements contract prohibits power purchases from other
suppliers, except QF's. The full requirements purchaser may
welcome the QF as a second source of power. Rural co-operatives
are required to seek competitive bids for all new capacity. There
is potential here. There are over 1000 rural electric co-ops in
the U.S.and over 2000 municipal electric systems and joint action
agencies.
Now let's look at some new developments in the industry and in the
law which will affect your competitive position. Bidding and new
market opportunities have lead to the appearance of a new player:
the independent power producer or IPP. An IPP is a generating
facility which does not qualify under PURPA and which is not part
of a utility's rate base. Typically an IPP burns natural gas or
other fossil fuel but does not cogenerate. This is because it's
easier to develop a project if there is no steam host involved. An
electric utility or its unregulated subsidiary may own more than 50
percent of an IPP. Both fuel use and ownership structure can keep
an IPP from qualifying under PURPA. Another characteristic of many
IPP's is that they have a large capacity - often over 100
megawatts. As yet, few IPP's are in operation, but 1500 megawatts
of IPP capacity is under construction. IPP's are subject to
regulation by the FERC under the Federal Power Act. The rate
charged' by an IPP for power sold to a utility must be approved by
the FERC. This has not been an insurmountable hurdle. The FERC
has been receptive to rates resulting from RFP's where the
utility's avoided cost is the benchmark.
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IPP's also are regulated by the Securities and Exchange Commission
under the Public utility Holding Companies Act. SEC regulation
under PUHCA has been a problem for IPP developers. They have
lobbied long and hard to change the law. It looks as though they
may have succeeded. On February 19, 1992, the Senate passed The
National Energy Security Act (S. 2166). That bill grew out of the
Bush Administration's National Energy Strategy which was issued
last year.
Title XV of the National Energy Security Act creates an entity
called the Exempt Wholesale Generator or EWG. An EWG is simply an
IPP which meets certain requirements set out in the act and so
notifies the Securities and Exchange Commission.
The non-utility generating industry has long expressed the concern
that PUHCA reform would allow, utilities . to purchase power .at
wholesale from their own unregulated affiliates. The concern was
that an affiliate of the purchasing utility is likely to have a
competitive advantage over other potential power suppliers. The
National Energy Security Act addresses this concern by prohibiting
EWG's from selling power to affiliates. The Act also allows state
commissions to consider the impact of purchases from EWG's upon the
purchasing utility's ratepayers. State commissions also can
consider other matters including the impact of EWG's which use
highly leveraged financing. Title XV has not yet become law, but
a similar provision is likely to be a part of energy legislation
passed by Congress this year.
The new energy law may also address another issue which is near and
dear to non-utility generators. That issue is mandatory wheeling
or transmission access. If wheeling is not addressed in the
legislation,it probably will be the subject of an FERC rulemaking.
The FERC already has addressed the question of wheeling on a case-
specific basis in recent orders. In some cases, the FERC has
required QF's to give up their right to sell power to utilities in
return for wheeling rights on the same footing with other utilities
and IPP's.
PUHCA reform has been on the horizon for several years. It is
viewed by many as a necessary step toward a competitive market for
wholesale power. This will help insure that the electric consumer
has access to the lowest priced electricity. In an era of high
electric prices, this is a significant goal.
Another critical result of PUHCA reform has received little public
discussion. That question is: How will PUHCA reform affect QF's?
For our purposes today, how will it affect your projects?
Existirtg QF's will probably feel little or no impact. But the
impact on future projects may be significant. In a nutshell, there
will be more competition. The competition will be larger and may
be backed by major utilities.
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On a purely competitive basis, some IPPs may be able to bid a lower
price per unit due to the economies of scale. Natural gas prices
are at an all-time low as well. But landfill gas projects may have
the edge when it comes to fuel supply. Natural gas prices and
delivery problems won't affect landfill gas. One possible long
term result of PUHCA .reform is that we will once again see an
electric generating industry consisting of large generating plants
owned by utilities or, more accurately, by their affiliates. This
time the utility plants will be located in the service territories
of other utilities. The small, decentralized generating plants
which PURPA envisioned, together with the fuel diversity PURPA
intended to create, may become relics of the past.
There have also been recent attempts to emasculate PURPA. One
failed proposal would have eliminated the utility's obligation to
purchase power from QF's in states which allow utilities to
purchase power from IPP's. There was an exception for QF's which
use solar, wind or hydroelectric technology. This type of
provision has been proposed in the past and probably will be
proposed again. I'm sure that many project developers-who would
have been affected by this proposal were unaware of it.
Another recent proposal would have precluded states from requiring
utilities to pay more than avoided cost for power purchased from
QF's. This would have eliminated certain state laws which
recognize the benefits associated with renewables by setting a rate
structure which specifically encourages those projects. This
proposal has appeared several times during the last year.
There seems to be a sense in Congress that PURPA projects no longer
need special encouragement. Congress recently rejected attempts to
extend the tax credits which support the production and sale of
landfill gas. Another proposal which failed was a tax credit for
production of energy from renewable sources.
For many years, the voices of the non-utility generating industry
were two or three national trade groups dominated by large
developers. Many of the more active developers are now interested
in developing IPP's. They supported PUHCA reform as did many
utilities. PUHCA reform and IPP's are concepts which are
consistent with this era of competition and reduced regulation. It
doesn't look like the voices of the industry are as committed to
encouraging renewables. These technologies have not had a strong
voice in Congress or in many states. I think this is a good time
for proponents of renewables and waste to join together and protect
their interests under PURPA.
In spite of increasing competition, this may be just the right time
to market your electric power based on its benefits to the
environment. And that is what I'll turn to in the last section of
my talk. While the IPP's and utilities have been fighting over
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PUHCA reform, state commissions have become increasingly aware of
the environmental impact of electric generation. This is important
because the state commission sets the utility's avoided cost and
has the ability to encourage utilities to favor specific
technologies.
An emerging trend at the state level is the consideration of
environmental externalities in connection with the regulation of
electric utilities. By externalities, I mean the residual
environmental impact of a generating facility after it complies
with current standards for pollution control.
States have recognized externalities in different ways. One way is
by statute which provides a buy back rate higher than avoided cost
for electricity generated using specified technologies. Another
approach is the set-aside which designates a block of capacity need
to be filled by a particular technology. Still another approach is
to quantify the environmental impacts of various fuels . and
technologies. The next step is to monetize those impacts and
include the environmental cost as part of the cost of constructing
a proposed generating facility.
Let's look at what some states have done in this regard. Illinois
mandates a higher buyback rate than avoided cost for utility
purchases from QF's fueled by solid waste and landfill gas. The
buyback rate is equal to the utility's retail rate. The utility
receives a credit against its state tax obligations in an amount
equal to the difference between its avoided cost and the amount
paid to the qualifying facility. The qualifying facility in turn
must repay to the state a sum equal to the utility's tax credit.
Repayment must begin at the end of a 10 or 20 year power sale
contract. Connecticut has a similar law but with no repayment
obligation. Other states have combined the set-aside with payment
of a rate above avoided cost to facilities which use renewable
fuels. Iowa requires each utility to buy 15 megawatts of renewable
power at an incentive rate. Still another approach is to assume
that a utility needs capacity whether or not this is the case, for
purposes of calculating the avoided cost payable to QF's using
renewable fuels.
The approaches I just mentioned do not attempt to quantify
environmental externalities. They simply recognize that |a given
technology will benefit the environment. The higher rate will
encourage the preferred technology. Where utilities do not need
new capacity in the near future, the avoided cost does not include
a capacity component. In those states, renewable fueled power
would not without this type of law.
Public "utility commissions in several states have addressed the
question of externalities in the utility planning process. States
which use least cost planning try to insure that a utility selects
the least expensive alternatives for new capacity. Consideration
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of environmental costs is a logical expansion of that approach.
The next step would be for a state to include the concept of
externalities in the avoided cost paid to qualifying facilities.
Thus, technologies which pollute the environment would be more
expensive. QF's which allow utilities to avoid or defer such
plants would receive a capacity payment which reflects the
environmental cost which has been avoided. To date few states
have taken that second step.
California is one state which will include environmental
externalities in the price utilities pay for QF power. When
California utilities issue RFP's for capacity later this year,
winning bidders are likely to be paid environmental adders as part
of their avoided cost payments.
Quantifying and monetizing environmental externalities is time
consuming and expensive. In addition, there are any number of ways
of achieving the goal. In the recent California proceeding, eight
or nine intervenors each had a different proposal as to how the
externalities should be handled. The recognition of externalities
could make it easier for landfill gas projects to compete with the
IPP's. But it's expensive to participate in state proceedings
which require expert testimony. The cost could be prohibitive for
a developer of one or two gas projects. The emphasis on renewables
in California results from the fact that California already has
projects using several renewable technologies. California has
windpower, geothermal and solar projects in addition to landfill
gas. California also has serious air quality problems.
Because the externality concept is new, staff at one state
commission favors inclusion of only one half the externality value
in the utility planning process. They are even more nervous about
an adder to avoided cost because that will consumer rates. This
application of the concept of externalities is fairly new and will
continue to develop over the next several years.
The Massachusetts Department of Public Utilities issued an order
recognizing externalities in 1990 and is about to issue a second
order revising the methodology. It appears that the new
Massachusetts rule will recognize externalities only for planning
purposes. Illinois and Wisconsin also are likely to consider
externalities in the utility planning process, but not in
calculating avoided cost.
From what I have seen, states which include externalities in
avoided cost probably will limit that concept to QF's which offer
new capacity. Existing contracts will not be affected. In
addition, externality adders will probably not be available in
connection with sales of energy only. There are also many critics
of the quantification of externalities. It's not yet clear whether
this approach will become widely accepted.
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California has taken another innovative step by recognizing the
value of fuel diversity. Under a state law which went inter effect
in January, a portion of each utility's capacity needs is set aside
so that QF's fueled by renewables, including landfill gas, can bid
to fill that need. In the upcoming California RFP's, Southern
California Edison will set aside 175 megawatts for renewables while
Pacific Gas and Electric will set aside 22.5 megawatts. New York
has just issued a state energy plan which requires utilities to
contract for 300 megawatts of renewable fueled power during the
next three years.
This is the time to get involved and to set a precedent for the way
states view landfill gas. I don't favor the approach of
quantifying externalities. I believe the preferable approach is to
lobby for a law which guarantees a higher rate to specified
technologies. The state laws I described earlier are examples.
This approach is less precise than quantifying externalities. A
state law which limits higher payments to a few special
technologies may be easier to sell- because it is simpler to
administer" and because its impact is more limited than a full-
fledged adoption of externalities.
I believe there are and will be opportunities to carve out a niche
for renewables in many states. The key may be the term
"renewables". Landfill gas developers may have to join forces with
developers of other renewable projects. Otherwise the cost may be
prohibitive and the interest which is benefitted may be viewed as
too limited. This type of action may be necessary at the federal
level as well in order to insure the continuation of PURPA.
Where the electric industry is concerned, I'm sure you'll agree
that the old curse has come true: we do live in interesting times 1
Thank you for your attention. I'll be happy to answer your
questions.
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