United States ITT> A-«nn/R-fl5>-11fi
Environmental Protection EPA-6UU/K V4 UO
Ac*ncv ; • June 1992
Research and
Development
LANDFILL GAS
ENERGY UTILIZATION:
TECHNOLOGY OPTIONS
AND CASE STUDIES
Prepared for
Office of Air and Radiation
and
Office of Policy. Planning and Evaluation
Prepared by
Air and Energy Engineering Research
Laboratory
Research Triangle Park NC 27711
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EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA- 600 /R- 92-116
June 1992
LANDFILL GAS ENERGY UTILIZATION:
TECHNOLOGY OPTIONS AND CASE STUDIES
Don Augenstein
John Pacey
EMCON Associates
San Jose, CA 95131
EPA Contract No. 68-D1-0146
Work Assignment 15
(E.H. Pechan and Associates)
EPA Project Officer:
Susan A. Thomeloe
Global Emissions and Control Division
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
Prepared for
U.S. Environmental Protection Agency
Office of Research and Development
Washington, D.C. 20460
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FOREWORD
Landfill gas has been successfully used for energy at many locations in the U.S. and worldwide, providing
economic, environmental, and other benefits. However, landfill gas energy uses are also relatively new,
and technologies are far from "cut and dried.' There are limitations and special considerations with
landfill gas energy use; a number of landfill gas energy projects have experienced problems, or even
failed entirely. There is current need for documentation of experience and consolidation of information in
several areas regarding the use of landfill gas as a fuel.
This report reviews the various landfill gas energy uses, and their associated issues and constraints. It
also presents case studies of six landfill gas energy projects in the U.S. The report's purposes include
• Presenting overviews of use and equipment options, and technical and other
considerations with landfill gas energy applications.
• Providing information on projects that illustrate common landfill gas energy uses.
• Providing an awareness of limitations and potential pitfalls existing with landfill gas
energy use.
In addition to providing background on energy uses, it is anticipated that the report will help identify ai &s
needing attention, for entities such as researchers and equipment manufacturers. It is also hoped fiat
the report can provide information useful in identifying ways to facilitate the beneficial uses of landfill gas
by reducing nontechnical barriers.
The complexities of landfill gas energy uses are such that the discussions of many issues must be limited
to overviews. Where detail is available elsewhere the report refers to available literature containing that
information. This is also true for the case studies; these attempt to provide information so that a typical
reader with some limited background will have a reasonable understanding of the operation, based on a
representative description of a particular energy application. This document is not intended to provide the
degree of detail needed to design and operate a landfill gas energy facility.
The case studies rely on information provided by many individual operators, equipment manufacturers,
and others such as engineering firms. An effort has been made to verify statements and data as much as
possible. In particular, all sections of the report have been reviewed by the providers of the original
information and others with appropriate expertise. Background information is cited from literature and
other sources considered reliable, and it has also been reviewed.
PJG G640101AAOW
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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 tower energy content, resulting in moderate equipment
derating. Other issues that are of normal concern for landfill gas, such as forecasting its recoverable
quantity overtime, 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 tow, 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.
PJG G640101A.AOW f»
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• 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.
PJG G640101A.AOW iv
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CONTENTS
FOREWORD -. '. II
ABSTRACT J«
ACKNOWLEDGEMENTS Jll
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 Participates 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) 8
3.1.2 Process heating and cofiring applications. .„. 10
3.1.3 Boilerfuel 10
3.1.4 Reciprocating internal combustion engines with
electric power generation 10
3.15 Gasturbines 11
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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 Fuei 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 15
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 "3
5.1 A 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
5.22 Otay landfill and landfill gas system -. .31
5.2.3 Gas preprocessing and energy plant equipment 33
PJG G640101A.AOW vi
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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, Yoto County, California 63
5.6.1 Introduction and general overview .63
5.62 History of project implementation 65
5.6.3 Landfill and landfill gas extraction system 66
PJG G640101A.AOW vii
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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 Specif icattons, 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
PJG G640101A.AOW
viii
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ILLUSTRATIONS
Figure Paoe
1 Cost Per Kilowatt Versus Size .18
2 Waukesha Engine - Generator Sets at Brown Station Road Landfill........ 20
3 Energy Facility at Brown Station Road: Simplified Block Diagram 24
4 Cooper-Superior Engine: day Landfill 32
5 Electric Power Facility at Otay Landfill: Simplified
Block Diagram 34
6 Marina Landfill Electrical Generating Facility: Trailers Housing
Gensets 39
7 Electric Power Facility at Marina Landfill: Simplified
Block Diagram 44
8 Sycamore Canyon Electric Generating Facility: Genset Building 50
9 Gas Turbine/Electric Power Facility at Sycamore Canyon:
Simplified Block Diagram 54
10 Cleaver-Brooks Boiler at Plant of Ajinomoto. U.S.A .".58
11 Electrical Generation Facility at Yolo County Central Landfill 64
12 Electrical Power Generation at Yolo County Central Landfill:
Simplified Block Diagram 67
PJG G640101A.AOW be
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TABLES
Table Paoe
1 Comparison of Component Concentrations and Other
Properties: Pipeline ("Natural") Gas and Landfill Gas 3
2 Landfill Gas Energy Applications 9
3 Cost and Revenue Range for 1 MW Electrical Energy Project 16
4 General Features: Brown Station Road Energy Facility 21
5 Landfill and Landfill Gas System: Brown Station Road 22
6 Major Equipment Items: Brown Station Road Energy Facility 25
7 Engine Operating Conditions on Landfill Gas:
Brown Station Road 27
8 Economic Data: Brown Station Road Landfill Gas
Energy Facility 29
9 Power Generation and Revenue Calculations: Brown
Station Road 30
10 Electric Generating Facility at Otay Landfill 31
11 Landfill and Landfill Gas System Characteristics:
Otay Landfill 33
12 Details of Landfill Gas Pre-Processing Equipment at
Otay Landfill 35
13 Results of Source Test on Cooper-Superior Engine at
Otay Landfill 37
14 Revenue and Other Economic Data: Otay Energy Facility 38
15 Electric Generation at the Marina Landfill 40
16 Landfill and Gas System Characteristics: Marina 42
17 Details of Landfill Gas Pre-Processing and Engine-Generator
at Marina Landfill .45
18 Summary Results: Emissions Tests on Marina Engines 46
19 Economic Data for Marina Landfill Electrical Generating
Facility 48
20 General Information: Sycamore Canyon Landfill Gas Energy
Facility 51
21 Sycamore Canyon Landfill and Gas System Characteristics 52
22 Gas Pre-Processing and Energy Equipment at Sycamore Canyon 53
23 Some Emissions Test Results at Sycamore Canyon 55
24 Economic Data: Sycamore Canyon Generating Facility. 56
25 Steam Boiler Fueled by Landfill Gas: Basic Features 59
26 Landfill and Gas System Characteristics: Witters Grove 60
27 Summary of Energy Equipment Characteristics 61
28 Economic Data for Landfill Gas Fueled Boiler 62
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29 Basic Features: Electricity Generation at Yolo £6
30 Landfill and Landfill Gas System: Yolo 68
31 Gas Preprocessing and Energy Conversion at Yolo 69
32 Economic Data: Energy Facility at Yolo County Central
Landfill 72
33 SWANA Landfill Gas Facility Tour Sites 74
PJG G640101A.AOW xi
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ACKNOWLEDGEMENTS
Many individuals contributed substantially to the development of information in this report. Assistance to
the project came from guidance during the site visits, information provided, peer review, and in other
areas. The authors would like to acknowledge the following, with their contributions:
At the U.S. Environmental Protection Agency, Air and Energy Engineering Research Laboratory, Global
Emissions and Control Division: Susan Thometoe provided guidance and encouragement as well as
technical input, throughout all phases of this project. Robert Borgwardt reviewed the draft report.
At the Environmental Protection Agency, Office of Air Quality Planning and Standards: Mark Najarian
reviewed the draft report.
At the Brown Station Road Facility: Fred Castillo of the Maguire group arranged the site visit, provided
information and reviewed the draft report. Tom Bryda of Maguire, Sheila Lanier and Fred Berry of Prince
George's County, and Richard Ay and Wayne Brashears of Curtis Engine all provided information during
and after the facility visit. Dave Leonard of Potomac Electric Power Company provided rate information.
At the day Landfill: Alex Roqueta and Frank Wong of Pacific Energy provided information on the landfill
and energy facility. Stan Zison and Ed Cadwell of Pacific Energy also provided background information
before the site visit.
At the Marina Landfill: David Myers guided the facility tour. David Myers, Rick Shedden, and Michael
Coulias provided information on the facility at various times: the engine operation information was
provided by Michael Coulias. All are employees of the Monterey Regional Waste Management District.
At the Sycamore Canyon Landfill: Robert Anuskiewicz and Peter Truman of Solar Turbines provided
information on the site. Peter Truman guided the facility tour.
At the Raleigh, N.C. boiler facility: Bill Rowland of Natural Power, Inc.. guided the tour and provided
information on the facility. Ron Hoover and Gary Faw of Ajinomoto USA provided information on the
boiler; Ron Hoover also reviewed the draft report. Jim Levitt of Palmer Capital also provided review of the
site visit report.
At the Yob County Central Landfill: Jim Hiatt of Yolo County. Marshall Carpenter of EMCON, Marvin
Yadon, on-site facility operator, Richard Ontiveros and David Marquez of Palmer Capital, and Ted
Landers of Perennial Energy all provided information on the landfill and energy facility. Philip Ziminsky of
Stowe Engineering reviewed the draft report
Waukesha Engine Division of Dresser Industries: Greg Sorge and Walter Pontell provided information
during report preparation.
Caterpillar Corporation, Engine Application Division: Curtis Chadwick provided information early in the
project, and comments on the report.
Browning-Ferris Industries: Richard Echols reviewed the draft report.
George Jansen, of Laidlaw Gas Recovery Systems, provided the text of appendix L The Economics of
Gas Recovery Systems in the United States," a presentation made on February 27,1992. in Melbourne,
Australia.
PJG G640101A.AOW xii
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Waste Management of North America, Inc. (WMNA): Chuck Anderson, Phil Gagnard and others provided
helpful comments. In addition, for this report, WMNA prepared appendix M. which describes the design
and operational philosophy of their 25 current landfill gas energy projects.
California integrated Waste Management Board (CIWMB): Francisco Guterres and Pat Bennett reviewed
the draft report. They also circulated the draft report for review to Heather Raitt of the California Energy
Commission, and Renaldo Crooks of the California Air Resources Board. Heather Raitt's comments,
forwarded through the CIWMB, are appreciated.
Cambrian Energy Systems: Robert Hatch and Tudor Williams commented on tax credit and other issues.
Mike Miller, of Wayne Energy Recovery, Inc., reviewed the draft report.
Bill Owen, of Michigan Degeneration Systems, provided the write-up on the recent landfill gas energy
project, which began operations in January 1992 (see appendix N).
Pat Lawson of the Energy Technology Support Unit (ETSU) of the United Kingdom Department of Energy
reviewed the draft report and provided information on U.K. landfill gas energy projects.
John Benemann, consultant, provided numerous helpful comments.
Frederick Rice, F.C. Rice & Company, provided many helpful comments and suggestions on the draft
report.
PJG G640101A.AOW xiii
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CONVERSIONS
Readers more familiar with metric units may use the following to convert to that system.
Nonmetric
acre
Btu
ft
ft2
ft3
gal.
hp
in.
in. H2O (head)
in. Hg
Ib. mass
inch
mile
psi
U.S. ton
Temperature
Times
0.4047
252
0.3048
0.0929
28.32
3.785
0.748
2.54
248.9
3386
0.4536
2.54
1.609
6895
0.907
Yields Metric
hectares
Calories
meters
square meters
liters
liters
kilowatt
centimeters
Pascal
Pascal
kilogram
centimeter
kilometer
Pascal
metric ton
Degrees Celsius - 0.556 (Degrees Fahrenheit - 32)
Degrees Fahrenheit -1.8 (Degrees Celsius) * 32
PJG G640101A.AOW
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1. INTRODUCTION AND BACKGROUND
This reports primary purpose is to provide information on landfill gas energy uses. The report is
addressed to a range of readers, presumed to include not only those familiar with landfills, landfill gas
energy, and related issues, but also some who may have relatively little familiarity with these areas.
A major report focus is case studies that document experience at representative U.S. sites where landfill
gas has been used for energy. To accommodate needs of the expected range of readers, the report also
presents background that should be useful to those developing knowledge of landfill gas energy uses,
and helpful for understanding of the case studies. Thus, the first section of this report provides general
background relating to landfills and landfill gas energy uses. This is followed in the second section by a
discussion of technical issues associated with landfill gas as a fuel—including the specific characteristics
of landfill gas as a fuel, and particular needs occurring with its use. The third and fourth sections of the
report cover equipment issues and economics. These are followed by case studies and conclusions. It is
hoped that this accommodates the needs of the anticipated range of readers.
The following section provides background primarily for the benefit of those who may have limited
familiarity with solid waste landfills, landfill gas, and landfill gas energy topics. Some of the basics
pertinent to the use of landfill gas as a fuel include
• what landfill gas is, and its origin
• its composition
• forecasting the quantity recoverable for fuel uses over time
• methodologies for its recovery
• environmental issues with landfill gas extraction and energy use
• regulatory demands and constraints regarding its use
These are covered below to provide a context for further discussion of energy applications in later
sections. Summary discussions of certain topics are supported with more detailed information in
appendices.
1.1 Landfills and Landfill Gas: General
Sanitary landfilling is the main method for disposal of municipal and household solid waste or refuse
(•garbage") in the United States. With current practice at landfills (no longer called 'dumps*), wastes
received are spread, compacted, and covered daily with a soil cover to reduce blowing litter, manage bird
and rodent activity, and control odors. The process continues over a given area until a planned waste
depth is reached; wastes are then covered with a final cover that has a relatively impermeable component
(often clay) to limit surface-water infiltration. Sanitary landfilling increased sharply in the U.S. in the early
1970s as open dumping and incineration were restricted. An estimated 145 million tons' of wastes are
currently landfilled annually in the U.S. (Kakjjian. 1990).
Most early practitioners of sanitary landfilling apparently trusted that waste decomposition would be of
minor consequence. However, even maintenance of an oxygen-free and relatively dry landfilled waste
For readers more familiar with metric units, conversion factors are provided at the end of the front matter.
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environment still permits certain biological reactions; these produce "landfill gas," and its generation can
be significant.
Landfill gas consists principally of a mix of two gases: methane (chemical formula CH4) and carbon
dioxide (chemical formula CO2). It is generated through bacterial decomposition of organic refuse in the
absence of oxygen (anaerobic fermentation) (Geyer, 1972; EMCON, 1982, Gas Research Institute,
1982). It is produced by nearly all landfills in which refuse is buried such that oxygen is effectively
excluded. Although many reaction steps and intermediates can be involved, the basic biochemical
reaction is exemplified by the decomposition of cellulose (the principal component of paper, and a
constituent of much other refuse material):
n(C6H10O5) + nH2O >3nCH4 + 3nCO2
cellulose water (bacteria) methane carbon dioxide
Though this reaction scheme is simplified, It represents the overall process fairly well; most landfill gas is
produced from decomposing cellulose, and most cellulose that decomposes yields methane and carbon
dioxide.
Because of its methane gas component (the same methane that makes up "natural* or pipeline gas),
landfill gas is a fuel. With proper allowances for its properties, landfill gas can be used for fuel in many
applications where other fuels, particularly natural gas, are used. These fuel uses of landfill gas are the
major focus of this report.
Landfill gas can be a significant energy resource. It is currently used at more than 100 U.S. sites
(Government Advisory Associates, 1991): its use is continuing to expand. Estimates of the ultimate
energy potential of U.S. landfill gas vary, but information in various references (U.S. EPA, 1991; American
Gas Association, 1980) suggest recoverable energy potentials ranging between 0.2 percent to over
1 percent of the total of U.S. energy use. Though the expressed percentage of U.S. energy use might
appear modest, the quantities are significant, given the total amount of energy the U.S. uses.
1.2 Composition of Landfill Gas
Characteristic composition ranges for landfill gas are shown in table 1. These are typical for "as
extracted" gas as tt is recovered. Also shown for comparison are the properties of "natural" or pipeline
gas. As seen in table 1, landfill gas consists primarily of methane and carbon dioxide, usually in ctose-to-
equal amounts. In contrast to pipeline gas, landfill gas also contains significant amounts of water vapor
and traces of various organic compounds. Almost all of the organic compounds found in the gas (usually
referred to as non-methane organic compounds [NMOCs] or sometimes reactive organic gases (ROGsJ)
originate through evaporation into the gas of the man-made solvents, propellants, and similar materials
discarded in the refuse stream; paint solvent vapors are one of many possible examples in this category.
Further discussion of these landfill gas components is presented elsewhere (Gas Research Institute,
1982; Emerson and Baker, 1991). Landfill gas as extracted can contain nitrogen and, less frequently,
oxygen from air entrained as a consequence of extraction; the concentrations of these gases depend on
the extraction objective and approach (Augenstein and Pacey, 1991). Landfills also contain a large
amount of soil and other paniculate material, and the extracted gas can pick up and carry with tt a
significant amount of that paniculate material.
The landfill gas components other than methane have effects that are often substantial on its energy
uses. Carbon dioxide, nitrogen, and (to a slight extent) water vapor can result in dilution and other effects
that moderately reduce energy equipment capacity. The trace organic components (particularly the
halogenated hydrocarbons) and particulates can cause serious energy equipment problems, including
corrosion and accelerated wear. These effects are discussed in more detail in the next section.
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TABLE 1. COMPARISON OF COMPONENT CONCENTRATIONS AND OTHER PROPERTIES:
PIPELINE ("NATURAL") GAS AND LANDFILL GAS
Component
Methane, CH4, percent
Ethane + Propane, percent
Water vapor, percent
CO2, percent
Nitrogen, other inerts, percent
Trace condensible hydrocarbons
(NMOC's; ppmv as hexane)
Chlorine in organic compounds
(micrograms per liter)
Hydrogen sulfide
(parts per million)
Higher Heating Value, Btu/ft3
Pipeline Gas
90-99
1-5
<0.01
0-5
0-2 (typical)
•0-
•0-
upto15
950-1050
Landfill Gas
(as extracted)
40-55
-0-
1-10 (typicaO
35-50
0-20
250-3,000 (typical)
30-300
to 200
400-550
Information from sources including references (Gas Engineers Handbook, 1965; EMCON, 1982). Units
are those most commonly used for the stated component.
1.3 Estimating the Gas Recoverable for Energy Uses
Energy users have a critical need to know the gas quantity potentially recoverable over time from a landfill
for energy use. The approaches that can be used to estimate this include modeling and field extraction
tests. This topic is important because misestimates of gas availability are among the common causes of
problems with energy applications. For readers interested in forecasting gas availability for end uses,
further discussion is presented in appendix A.
1.4 Gas Extraction Systems
The landfill gas extraction system collects gas generated by the landfilled refuse, and delivers it to the
energy application. The overall concern of the gas energy user is that the system will continue to provide
a reliable supply of gas in the necessary quantity. Collection efficiency may also be a concern; it depends
on design and operational factors and may range between 50 and 95 percent. Further discussion of gas
collection is presented in appendix B.
The topics of gas recovery systems, and extraction practice are important because difficulties with
collection systems are also among the common causes of problems with energy facilities.
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1.5 Environmental and Conservation Aspects of Landfill Gas Energy Use
The energy uses of landfill gas have significant environmental consequences that are considered to be
predominantly beneficial. The gas extraction process helps abate both gas migration hazards and the
emission of reactive organic gases that contribute to air pollution. A particular current concern is the
contribution of landfill methane emissions to atmospheric methane buildup, "radiative forcing," and
resulting climatic effects ("greenhouse effect"). Extraction and use mitigates these. The energy use of
landfill methane also "offsets* fossil fuel use elsewhere, and reduces secondary pollution and the
consequences of carbon dioxide emission that could otherwise be produced by use of that fossil fuel. Its
energy use also comprises conservation. These issues are discussed elsewhere (U.S. EPA, 1991,
Thometoe and Peer, 1991; Augenstein, 1990); a further description of these issues with references to
relevant literature is presented in appendix C.
1.6 Regulatory Issues
Those who become involved with using landfill gas for energy will generally be affected by many
regulations that pertain to landfill gas energy use. Among the most important of these are
• Proposed federal regulations associated with the recently amended Clean Air Act.
These propose limits above which NMOC/ROG emissions must be controlled, and
specify the required degree of abatement. As one consequence of these regulations,
most larger landfills now without energy systems, but which would be capable of
supporting them, will probably be required to install gas extraction systems.
• Regulations applicable to landfill gas management, which vary locally across the U.S.,
and that define the performance of gas systems based on factors such as prevention
of off-site migration and reduction of atmospheric NMOC/ROG emissions.
• Regulations associated with the Public Utility Regulatory Policy Act (PURPA). These
facilitate the sale of electric power produced from landfill gas to utility grids.
• Federal tax credit incentives that significantly improve the economics of the gas
recovery process and of energy uses.
• State regulations that provide incentives to energy production.
• Emission restrictions that apply to energy equipment.
An overview of regulations, regulatory issues, and their consequences is presented in more detail in
appendix 0.
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2. USE OF LANDFILL GAS AS A FUEL—TECHNICAL ISSUES
This section describes the technical issues regarding use of landfill gas as a fuel. Noted as background is
that a very large body of information on energy and equipment fundamentals is available from a variety of
sources, such as standard texts, and equipment manufacturers. As such information is widely available
elsewhere, discussion of such standard energy technology aspects will be limited below. This and later
sections concentrate on the unique aspects of landfill gas, compared to conventional fuels, for which
different approaches are needed and from which performance differences, surprises, and problems, may
arise. These aspects would normally be of greatest concern to energy users. Discussion also
concentrates more on applications (detailed further in section 3) that appear the greater near-term
opportunities. Thus electrical and boiler use issues are emphasized over, for example, those with
pipeline gas preparation.
Some major issues that must be recognized and dealt with in energy use are
• determining the composition and characteristics of the gas
• potential corrosion effects caused by gas components
• effects of particuiates
• gas cleanup
• dilution and other performance reduction effects
• toad factor
These are addressed briefly below. In addressing these issues it is assumed that readers have at least
some understanding of energy technology.
2.1 Gas Composition Analysis
In contrast to the case with more "conventional" fuels, users of landfill gas for energy may need to check
their fuel composition fairly regularly. Landfill gas composition and energy content can change because
of extraction procedures, leaks, or other factors. Gas systems often need to be "tuned" to provide a gas
stream of appropriate quality to keep energy equipment running, and this tuning can require frequent well-
by-well analysis. The gas will also contain a range of contaminants, whose level varies by landfill and
over time. Since gas composition can have important energy consequences, composition analysis is
reviewed briefly in appendix E.
2.2 Corrosion Effects
Serious equipment corrosion can be associated with landfill gas energy use. Corrosion is generally due
to hydrogen chloride and fluoride resulting from combustion of halocarbons (chlorine- and fluorine-
containing or hatogenated, organic compounds) that are present in the gas. These compounds include,
for example, the chlorofluorocarbons (CFCs) that were widely used in the past as refrigerants and aerosol
propellants. Though CFCs are now being phased out because of environmental effects, they are still
found in landfill gas (as old aerosol containers in the landfills release their contents over time). Other
chlorinated compounds (such as industrial degreasing and dry cleaning solvents) also find their way into
landfills and then into the gas.
Though levels of hydrogen chloride in combustion product gases are tow, the hydrogen chloride is readily
reactive with, for example, the metal in reciprocating internal combustion (1C) engines. Damage can
result when metal in 1C engine cylinder walls and other engine parts (including exhaust valves) reacts and
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is removed. Hydrogen chloride and fluoride can also react with metal in other equipment such as the
tubes of boilers. Secondary damage can result from the buildup of solid corrosion products on the
surfaces of moving engine parts. For example, deposits can reduce piston/cylinder or other lubricated
surface clearances to zero, at which point the engine seizes and will be severely damaged. Case studies
presented later in this report document such damage.
One engine manufacturer reports, based on many tests, that the content of chlorine in landfill gas,
chemically bound in volatile compounds, is typically between 60 and 200 micrograms per liter of gas1.
Because of corrosion effects, all engine manufacturers recommend that landfill gas be analyzed for its
content of chlorine in chlorinated compounds (Chadwtek, 1989). Various operating modifications (to be
discussed later) are also recommended to prevent engine wear. The measures taken are generally, but
not uniformly or completely, successful in limiting corrosion effects.
The gas can also contain other potentially troublesome chemical contaminants; for example acetic and
other organic acids in the landfill gas condensate can react with steel. Problems from this source are,
however, relatively minor.
2.3 Particulates and Their Effects
Experience has shown that paniculate contaminants entering with the gas can build up in the oil used in
many landfill gas engines, accumulating until they present problems. Paniculate contaminants are of
various types, including silica (a common soil component), iron salts (where steel is used in collection
systems), and other normal soil components. (One interesting source of paniculate contaminants in oil is
a gaseous silicon compound, dimethyl siloxane, which will combust to products including silica. It is not
removable by normal gas cleaning methods.)
Discussion of these compounds, and their effects on 1C engines, are presented in references including
Vaglia, 1989, Buildup of these components in oil above certain levels can contribute to wear. The
materials can damage cylinder linings and rings; heavy deposits can also form on combustion chamber
surfaces. The potential deleterious effects of paniculate contaminants, as well as gaseous and liquid
contaminants discussed earlier, make gas cleanup extremely important, as discussed next.
2.4 Gas Cleanup
Users of landfill gas for energy have often practiced what could be considered relatively limited cleanup
(this excepts pipeline gas preparation, discussed later). Limited cleanup has provided satisfactory
operating results at may sites including one case study site of this report. In other cases, however, the
application of more apparently thorough cleanup, which for landfill gas can be considered 'state-of-the-
art,' has not prevented frozen' engines, or corroded equipment, and similar mishaps.
The primary "generic* cleanup approaches are filtration and condensate knockout. These are sometimes
augmented by refrigeration, and less often by desiccation and other approaches.
Landfill gas filtration can employ the same type of equipment as used (for example) in large-volume air
cleaning for internal combustion engines and combustion gas turbines. Filters may include simple particle
size cutoff or coalescing models. Some description of these is included in the case studies.
Refrigeration, to remove gas steam contaminants by condensation, is now practiced at a number of sites.
Typically the gas stream may exit a landfill wellhead at a temperature exceeding 100*F, saturated with
water vapor; cool (with condensate removal) to near ambient temperature on its way to the energy facility;
and then be refrigerated further, for contaminant removal to a dew point (typically) of 1*C or about 34'F.
This cooling will typically remove between 80 to 95 percent of the water and a fraction of other
Personal communication, Greg Serge. WauKesha Engine Division of Dresser Industries. WauKesha. Wisconsin, June 1991.
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condensible contaminants (which is a function of the specific contaminant's vapor pressure,
concentration, and other factors).
Where refrigeration is practiced, icing and high parasitic energy consumption normally limit gas cooling for
cleanup purposes to a lower temperature slightly above the freezing point of water. The problem with this
limit is that gas compounds that may cause corrosion problems, in particular the lower-boiling
halogenated compounds that are a major part of the threat to equipment are not removed. Where
prevention of condensate (ice or liquid) in the treated gas is a must—for example where compressed
landfill gas is to be pipelined in cold climates—chemical desiccation may be applied to reduce dew points
to well below the freezing point of water.
Approaches to more completely remove contaminants from landfill gas (but that still leave C02 in) have
been applied; on a commercial scale, the Olinda site (Vaglia; 1989, GRCDA, 1986) uses the Selexol®
process to remove contaminants. Other approaches, including absorption of gas components on
activated carbon, have been demonstrated but only on a pilot scale (Watson, 1990).
As a summary observation, the cost-effective cleanup methods to date (except those for purification of
gas to pipeline standards) all leave some fraction of contaminants, and particularly halocarbon
components, in the gas. These contaminants are difficult to remove because of their low boiling points,
concentrations, poor affinity for traditional solvents or a combination of these factors. The economic
tradeoffs between more complete removal of various contaminants, and simply dealing with their effects
when the gas is used for energy (by such means as more frequent engine oil changes) and other engine
design and operational modifications, are not completely evaluated. The correlation between degrees of
cleanup, observed levels of energy equipment corrosion, and performance needs further analysis.
These observations about cleanup pertain to most energy applications, except purification to pipeline
quality gas, where far more thorough cleanup is applied to remove nearly all compounds except the
methane component from the gas. Pipeline gas cleanup will be discussed further below.
2.5 Dilution and Other Performance Reduction Effects With Landfill Gas
Because landfill gas contains inert components—close to half carbon dioxide, and smaller amounts of
nitrogen .and water vapor—{he performance of energy equipment is typically reduced compared to its
performance with more "conventional" fuels such as pipeline gas. The equipment rating does not (as
might first be thought) decrease proportionally to the gas energy-content reduction (i. e., the rating of
equipment on 500 Btu per cubic foot [Btu/ft3] landfill gas does not decrease to half the rating of equipment
on 1,000 Btu/ft3 pipeline gas). The fractional loss of rating (derating) instead depends in a complex way
on fuel-air mix heating value and the combustion characteristics of the landfill gas used in the energy
application. For naturally aspirated 1C engines, the dilution effect of C02 at equal input flow rates o1 fuel-
air mix can reduce the energy content of the gas in the cylinder's combustion chamber by about 8 to
10 percent, which will reduce the power output by this amount based on energy throughput
considerations alone. The inert components can also have slight secondary effects in reducing flame-
front velocity and combustion temperature, which reduce efficiency by a slight additional amount, so that
the engine rating is reduced, overall, by 10 to 12 percent.
For energy equipment that bums pressurized nonstoichiometric fuel mixes, such as lean-bum 1C engines
and gas turbines, energy efficiency losses occur from another source: landfill gas at atmospheric
pressure requires compression work that is a parasitic toad. This is in comparison to pipeline gas, which
is typically available at the required pressures. This tends to reduce efficiency (which can vary somewhat
independently of output) by 5 to 15 percent for lean-bum engines on landfill gas.
In boilers and process and space heating applications where landfill gas is used in burners, heat output
reduction at constant total fuel-air volumetric throughput is about 12 percent. About 10 percent of the
reduction is because of inert gas dilution, with the remaining 2 percent because of increased stack heat
losses. Refrigeratton, if practiced for cleanup, can reduce efficiency by (very roughly) another 5 percent.
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Overall, landfill gas energy users should be prepared for energy equipment rating tosses that range
between 5 and 20 percent, depending on the application.
2.6 Load Factor ("Use H or lose HN)
One consideration regarding landfill gas is that there is currently no well-established way of storing it It
must be used essentially as it is generated, or it is tost. This means that it is most suitable for energy
applications that are constant and continuous such as electric power generation, pipeline use (with
purification), or continuous or near-continuous plant process use. Intermittent uses such as space
heating can be practical, but are more efficient if combined with other energy applications, such as
absorption cooling, that can assure higher year-round gas use. Some of the difficulty can also be
overcome by using landfill gas to supply that part of the energy demand that is continuous, and other
fuels to meet that part that may be variable.
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3. ENERGY APPLICATIONS AND EQUIPMENT
Table 2 presents some of the more common and important current landfill gas energy applications and
potential future applications. Considerations regarding their use are presented in the text. A brief
discussion of applications, in order of increasing complexity, is presented next.
3.1 Current Applications and Equipment
3.1.1 Space heating (and cooling)
Normal gas-fired space heating equipment in widespread use can, with moderate burner and other
modifications, use landfill gas. Such use has been limited to date because appropriately sized users of
space heat are only infrequently located near landfills, and piping costs to more distant users can be
prohibitive. Depending on climate and other factors, heat energy supplied by 500,000 cubic feet per day
(cfd) landfill gas could correspond to heating needs of a 200,000- to 1,000,000-square-foot (or several
acres of floor space) complex, large by normal standards. Space heating loads also vary undesirably
over time, both during the day and by season; a higher overall load factor for the gas use can, however,
be obtained by combining absorption chilling with space heating in temperate climate zones. Condensate
TABLE 2. LANDFILL GAS ENERGY APPLICATIONS
Current Applications1 Degree of Use2
Space Heating (and cooling) Limited
Industrial Process Heat Limited
Boiler fuel Moderate
Electrical Generation: 1C engines Most common
Electrical Generation: Gas turbines Common
Electrical Generation: Steam Turbine Limited
Purification for pipeline use Moderate
Potential Future Applications
Electric generation using fuel cells
Compressed methane vehicle fuel
Synfuel or chemical feedstock
1. Most significant actual or potential uses.
2. Statistics on use (such as in Government Advisory Associates, 1991) have included most, but not all,
facilities. In defining degree of use in terms of the fraction of the total landfill gas recovered and used
for energy in the U.S., limited- is about 5 percent, 'moderate' te 5 to 20 percent, 'common- is 20 or
more percent, and 'most common' is about 50 percent. A recent, more comprehensive update on
use has been presented (Thometoe, 1992).
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in equipment can be troublesome in space heating applications and poses a corrosion potential; gas
cleanup and construction materials are important. Despite these limitations space heating can work well;
one of the case study sites uses it. The equipment is also economical and available even on a small
scale.
3.1.2 Process heating and coflrlng applications
Several industrial applications, such as lumber drying, kiln operations, and cement manufacturing, can be
attractive applications for landfill gas. An advantage of many industrial processes, including drying
processes, is that fuel is required continuously, 24 hours a day. Landfill gas can be also used as a
supplemental fuel that meets a portion of the total demand. Many industrial processes such as cement
manufacturing may be relatively insensitive to the contaminant components resulting from landfill gas
combustion, and their gas cleanup costs may be quite low in such applications.
One application that can be attractive because of absence of gas cleanup needs, and frequently plant
proximity, is co-firing of the gas as supplemental fuel in a waste-to-energy plant.
3.1.3 Boiler fuel
This is an attractive use, particularly tor large industrial boilers with constant demand, or where landfill gas
can be used as a supplemental fuel. Conventional equipment can use landfill gas with relatively little
modification. One case study of this report, in section 5, describes a boiler application. To the extent that
sensitivity to gas contaminants can be determined, boilers may be less sensitive and their gas cleanup
needs less than, for example. 1C engine applications. The capital costs of boilers, discussed later, are
also attractive. Although steam users are not frequently located near landfills, the siting of boilers, or for
that matter other uses of 3.1.2, near landfills can be an alternative worth consideration.
3.1.4 Reciprocating Internal combustion engines with electric power generation
Reciprocating internal combustion engines, almost all driving electrical generators to produce electrical
power, are the most widely used landfill gas fueled energy equipment. Electrical generation occurs
because the output can be accepted (if not always at a high price) by the electric utility grid 24 hours a
day, and the power sale may be facilitated by provisions of PURPA. Although available statistics are far
from complete, data in the 1991 GAA yearbook (Government Advisory Associates, 1991) suggest that
electrical generation using reciprocating internal combustion engines is practiced at about 50 percent of
the landfill gas energy sites in the U.S., and electrical generation using gas turbines is practiced at an
additional (approximately) 15 percent, so that electrical generation is practiced at about 65 percent of the
total sites.
Almost all larger engines used in this application are made by three manufacturers—Caterpillar, Cooper-
Superior, and Waukesha. Each has in place more than 20 engines at landfill sites in the U.S. Lists of the
sites where the various models of the three manufacturers' engines are in place are presented in
GRCDA/SWANA, 1989.
The engine-generator set (genset) equipment is well developed and is used not only with landfill gas but
for numerous other applications; the landfill gas sets sold by the three manufacturers are largely identical
to those of the complete 'stand alone" package sets sold for use at remote sites such as offshore oil
platforms and other remote sites requiring electric power. Currently increasing degrees of automated
engine monitoring and control reduce the need for on-site operator attention. Genset electrical capacity
with landfill gas is typically 100 kW and up, with capacities between 1 to 10 megawatts (MW) being most
common because of economics. Multiple gensets are used to obtain the higher outputs.
The reciprocating engines are most commonly "lean bum" turbocharged designs that bum fuel with
excess air. Less commonly, they may be "naturally aspirated" without turbocharging (which as the term is
used also implies stoichiometrically carbureted, with air in the fuel-air mix just sufficient to bum the fuel).
The naturally aspirated engines are easier to operate because they are less complex, but they have
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reduced power output and unresolved emissions issues. When operated on landfill gas, reciprocating
engine power ratings are commonly reduced by 5 to 15 percent compared to operation on natural gas.
This derating is caused by different factors, depending on engine type: dilution effects in naturally
aspirated engines and parasitic load in lean-bum engines. The overall heat rate for electrical generation
with the more commonly used lean-bum engines (after all parasitic toads are deducted), is about 11.000
to 14,000 Btus of landfill gas higher heating value per kilowatt hour. For smaller scale electric generation,
this efficiency is quite good; this is one reason these engines are popular.
Landfill-gas-fueled generation comprises a rather small portion of the total use of such engines. Despite
this, the three manufacturers of these engines have modified both design and operating procedures so
that they can be said to have "landfill-gas-adapted" engines. With turbocharged engines, the need to
compress landfill gas initially at ctose-to-atmospheric pressure normally poses added capital and energy
costs compared to pipeline gas fueling. Compression of the fuel-air mix post-carburetion avoids some of
these costs and (along with other landfill-gas-specific adaptations) is now being applied by Caterpillar in
their 3516 series engines (Chadwick, 1990). Various design modifications, by all manufacturers, include
parts modifications for corrosion resistance, such as chrome valve stems and modified piston rings; pro-
prietary modifications are frequently involved2. One of the important operating modifications relates to
engine oil as recommended by the engine makers (Chadwick.1989). Oil is checked much more often
than is usual in other applications, sometimes as often as every 50 hours. Oil is changed frequently, as
often as every few hundred hours or when relatively low contaminant limits for chloride (chloride can
indicate corrosion as discussed earlier) or metal content are observed, according to manufacturer's guide-
lines. Specialized lubricating oils with high total base numbers (TBN; for discussion see Gonzalez, 1987)
are now recommended for landfill gas use. Chemically, the bases in these oils give the acidic combustion
products something to react with before they react with the metal of the engine. These can be thought of
as helping engines the same way that antacids help people (and by neutralizing the same acid).
With the design and operating modifications that have been made for landfill gas engines they can
generally be operated successfully at landfills. Yet, for reasons that are still not completely understood.
(but that may relate to presence or absence of various landfill gas operational and design adaptations)
some engines at some landfills encounter serious operating problems. They are most frequent during
initial operation..
3.1.5 Gas turbines
Combustion gas turbines are also widely used as landfill-gas-fueled prime movers (i.e., sources of
mechanical power) at landfills to drive generators. The justifications for their use in electric power
generation are the same as those for reciprocating internal combustion engines.
The gas turbines used at nearly all U.S. landfill sites are either Saturn or Centaur models made by the
Solar turbine division of Caterpillar. As of 1989, more than 30 Saturn or Centaur turbines were in use at
more than 20 landfills: lists of their applications are presented in Esbeck, 1989, and Maxwell, 1989.
The principal power-rating consequence of using,landfill gas as opposed to pipeline natural gas in
turbines is a decrease of 10 to 15 percent in the power rating, due to the parasitic toad associated with
compression of the landfill gas fuel to the turbine. When all factors are considered, a turbine has a
somewhat tower net efficiency in typical landfill gas applications than a reciprocating internal combustion
engine. The heat rate of smaller turbines is typically about 16,000 Btus landfill gas higher heating value
per kilowatt hour generated when parasitics are accounted for.
A factor to be considered in turbine operation is that turndown performance is poor-^hat is, turbines do
best at full load, and poorly if gas supplies are less than needed to supply full toad operation. Gas
contaminants have also apparently caused serious problems for some landfill-gas-fueled gas turbines.
These have included combustion chamber erosion and deposits on blades, resulting in severe and
2 Personal communication. Curtis Chriwick, CaMrpiRar Corporation. MossviHa. Illinois. September 1991.
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unanticipated damage in a tew cases. A well-documented instance of turbine damage and associated
cost is presented in Schtotthauer, 1991. The use of improved coalescing type filters (in combination with
other modifications) has apparently solved or forestalled problems at sites described in Schtotthauer,
1991. One danger of severe damage to turbines that does not exist with conventional fuels is that a large
"slug" of landfill gas condensate in the piping system could mobilize and reach the turbine (it is a
consideration with 1C engines as well). Methods for intercepting such slugs are required when this danger
exists at turbine sites.
Although problems are seen at some turbine sites, they appear to have solutions. Turbines have the
advantages of tow operator attention and maintenance needs.
3.1.6 Steam-electric
Steam-electric generation bums landfill gas in a boiler to produce high-pressure steam, which then drives
a steam turbine to generate electricity. A large amount of gas is needed for economic and efficient
operation; the result is that only a few U.S. sites use this approach, with few additional candidate sites
apparent where a stand-alone plant might be attractive. The economic difficulties of scale are a lesser
problem, however, if landfill gas can be delivered to supplement the conventional fuel at a conventional
steam-electric power plant: limitations here can be either piping costs or the on-stream time of the
conventional electric plant.
3.1.7 Purification to pipeline quality methane
Very stringent cleanup technology is applied to remove all components except the desired methane at a
small number (under 10) of the larger U.S. landfills to produce gas for pipeline use. The principal
objective not required of other cleanup approaches is neatly complete COg removal, but the criteria are
also stringent for the removal of other contaminants. The technology for cleanup to pipeline standards
(with needed gas compression to pipeline pressure) is expensive; most such projects were initiated in the
U.S. at larger landfills, where the economics of scale are attainable, during the early 1980s when gas
prices were high. Projects operating today all have favorable long-term contracts.
Several technologies are available for the necessary cleanup. Many of these originated as C02 removal
approaches applied first in the natural gas industry, through further adaptations for landfill gas appear to
have been major. Details of these can be found in several sources, including a rather comprehensive
review by Koch. 1986. The largest operator of facilities producing pipeline methane from landfill gas is Air
Products and Chemicals, Inc. (APCI) and the process in use by APCI is the Gemini® process; provisions
for this process's contaminant removal and destruction are interesting and discussed in Koch, 1986.
Because of recently falling natural gas prices, and because the largest landfills with best economics of
scale already have energy projects, additions to pipeline quality gas production from landfill gas in the
near future may be limited.
3.2 Potential Future Technologies
Landfill gas may be applicable to several technologies under development; these include fuel cells,
compressed gas vehicle fuel, and possibly synfuels production. A brief review follows.
3.2.1 Fuel cells
Fuel cells are essentially electrochemical batteries. They can operate on various primary fuels
(feedstocks) such as oil, natural gas, or coal. The potential primary fuels include landfill gas. As an
intermediate step the primary fuel is converted at high temperature to 'synthesis gas,' which is a mix of
hydrogen, carbon monoxide and dioxide, and other gases. This synthesis gas is what feeds the fuel cell.
Further discussion of fuel cell operation on landfill gas is presented in Leeper, 1986. Advantages include
tow emissions and quite high thermal efficiency (near 40 percent). It is a technology that has particular
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promise for economical electric power generation on a smaller scale. The technology is considered
sufficiently interesting that the U.S. EPA will be funding further trials (Sandelli. 1992).
3.2.2 Compressed gas vehicle fuels
Vehicle fueling with compressed methane is of high interest for environmental and other reasons, and
technology for such fueling is advanced. It was reported that in 1990 at least 700,000 vehicles operating
worldwide were fueled by natural gas (Rosen, 1990); such fueling is economically competitive in several
situations, and expanding. Digester gas has also been used at sites including Modesto and Los Angeles,
California (EMCON, et al., 1981). Using landfill gas would involve some purification, possibly to near
pipeline quality, then compression of the purified gas for reduced-volume storage and use on board
vehicles equipped with conversion kits. Although landfill gas applications have apparently been few, an
early study (EMCON, et al., 1981) projected favorable economics. The most attractive use is for fleet
vehicles, and in particular refuse trucks, which would need to return frequently to the landfill where the
gas would be available. Gas availability and economics both dictate that the vehicle fleets should be
large.
3.2.3 Synthetic liquid fuels and chemicals
Various technologies are available that could convert landfill gas to liquid fuels. These include
hydrocarbon production by Fischer-Tropsch, methanol synthesis by various routes, including chemical
catalysis at high pressures (Ham et al., 1979), or by partial biological oxidation. Most of these synfuels
approaches have been examined for large-scale feasibility using feedstocks such as gas from coal.
Synthesis gas-based chemical processes (for example, acetic acid manufacture) are also possible.
These technologies are projected to produce expensive products, even at the larger scales. The principal
difficulty with any of these, particularly fuels, would be that landfill gas generation can support a plant size
that is generally only 1 to 10 percent of the plant size normally contemplated for these technologies. The
small scale required with using landfill gas would appear to imply very high costs.
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4. COST AND REVENUE COMPONENTS
This section addresses cost and revenue components and particularly issues such as site specificity and
cost variability that are considered to be important to energy users. It is not intended to provide extensive
cost detail here, although some examples of costs and cost ranges are provided for illustration.
Comment is also presented on issues including electric revenue requirements, initial cost estimating, and
economics as barriers to landfill gas energy applications.
4.1 Components of Cost and Income
The cost and revenue factors to be considered consist of (1) capital costs, (2) operations and
maintenance costs. (3) royalty payments, (4) tax and other credits, and (5) energy-related revenues.
• Capital costs include costs associated with energy conversion and sometimes other
associated equipment such as that for gas extraction. They normally include the "up
fronr costs of implementing the project and plant, and may include other large lump
sum costs incurred during the project, such as for equipment replacement. Some
examples of capital costs include those for initial site improvements, energy
equipment, buildings, and pollution abatement equipment. They can also include initial .
legal costs, commissions, rights to gas. permits, and the like. They can vary widely as
discussed shortly.
• Operating and maintenance costs include costs associated with operating and
maintaining the capital plant. Items such as labor, equipment maintenance, materials,
debt service, and relevant taxes fall in this category. Operating and maintenance costs
can vary substantially and depend on factors including the end use, landfill
characteristics and configuration, gas composition, local rules and regulations, and
many others.
• Royalty payments are continuing costs that are usually proportional to energy revenue.
Royalties are negotiated and are occasionally changed as the marketplace, or other
factors, change. Royalties may be paid to the landfill owner, owner of the gas
extraction or delivery rights, or initial project developer. When they exist (a fair fraction
of projects have none) they are usually in the range of 5 to 20 percent of gross energy
sales.
• Federal tax credits are benefits proportional to gas energy delivery that were legislated
by Congress (Section 29 of the IRS code). These credits are a direct dollar-lor-dollar
offset to federal tax that would otherwise be payable by the business entity providing
the gas. The tax credits are allowable for extraction systems installed before the end
of the year 1992 and will extend through the year 2002. They have had ± significant
effect on improving economics and viability of projects that might otherwise not have
been implemented.
• Revenues for energy sales are most frequently based on prices of competing fuel or
energy. They can be based on costs of the equivalent in heating value of a fuel grade
petroleum product, on electricity sales (where cost is fixed by provisions of PURPA), or
on other energy commodities. Energy market price fluctuations can materially and
often adversely affect economics. Long-term contracts can often be executed, that fix
prices per unit of output and provide a substantial degree of security to developers.
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Possibly the most important aspect of costs, revenues and other benefits is their specificity to site and
situation; the site-to-site variation, even with the same application and scale, is far greater than is usual
with other energy technologies. The reasons include
• Component capital cost variations: Key components such as gas cleanup, utility
provisions (e.g., on-site water supply), and utility interconnects can vary in cost by at
least an order of magnitude. Other capital costs, such as those for gas and power sale
contract rights and pipelining, can be zero for many projects but may add substantial
percentages (up to 25 percent or more of the costs) to others. Energy equipment
costs can vary depending on details and whether the equipment is new or used. Fixed
costs, which are proportional to capital costs, vary correspondingly.
• Operating cost variations: As an example, landfill-gas-specific maintenance costs
relating to gas contaminants can vary by up to an order of magnitude. Other costs
such as royalties (where they exist) and operator cost can vary several fold.
• Benefits accruing per unit of energy delivered can vary (by about a factor of five for the
example of electric power), and also depend on whether the energy is sold to the utility
transmission system or avoids utility retail cost. Nonenergy credits allocated for
benefits such as for gas system maintenance and adjustment, and emission control
vary widely.
Development of detailed economics regarding application, scale, and the host of site-specific factors that
can exist is, as noted, beyond the scope of this report. (Also it should be noted that costs may be
expressed in several different ways in literature sources, with many data appearing contradictory).
Further discussion of various categories of costs—capital and capital-related, operating costs, and
revenue and benefit components—is presented in appendix F. Examples of cost data, presented next,
illustrate some typical costs and their levels of variation.
4.2 Cost Data: Examples
4.2.1 Hypothetical generating facility example: Cost component ranges
Table 3 presents example ranges for cost and benefit components that might be experienced for the
hypothetical case of a 1 MW electrical generating facility. (As stated earlier about 65 percent of landfill
gas energy facilities involve electrical generation). Note that capital costs are installed, that is,
engineering, design, permitting, and other costs are factored into the costs; ranges given are "best
estimates" generated by the authors for this report. The ranges suggest the potential for cost variability,
even where (as in this example) the application (electrical generation) and scale (1,000 kW) are fixed.
Note that electric sale price and other benefits per unit output may vary over an even greater ratio than
cost factors. Economic factors may impede the energy use of much of the landfill gas that is generated,
as discussed in more detail below.
4.2.2 Reported electric facility capital costs: GAA Yearbook
Some reported data on capital costs for electrical generation, are also illustrative. In the Government
Advisory Associates' 1988-1989 Methane Recovery from Landfill Yearbook, 38 electrical generating
facilities report information (capital cost and nominal electrical generating capacity) from which costs per
kilowatt of capacity may be calculated. The figures are for both current and projected facilities, including
intemal-combustion-engine-based facilities, gas turbine facilities, boiler/steam turbine electric facilities,
and in some cases facilities using unspecified generating methods. The capital cost per kilowatt for each
of these individual facilities, coded by facility type, is plotted against plant capacity in figure 1. All costs
have been adjusted to 1991 dollars. The data probably have imprecisions for several reasons (additional
plant costs experienced for postconstruction modifications may be omitted, experienced output may not
PJG G640101A.AOW
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TABLE 3. COST AND REVENUE RANGE FOR 1 MW ELECTRICAL ENERGY PROJECT
Capital Cost Ranges (Basis: 1 MW capacity)
Range of Capital Cost
(thousands)
Administration, Development and other1
Extraction system
Pre-treatment system
Energy conversion equipment
Typical Range2
30 -1,000
200 -1.000
10 -500
500 -2.000
850 -4.500
Typical Operating Cost Components
Operations and Maintenance
Debt Service (interest and amortization)3
Return on Investment (ROI)3
Other (royalties, etc.)
Typical Range2
$/kWh
0.01
0
0.01
0
0.03
0.03
0.04
0.04
0.02
0.09
Typical Revenue Components
Tax Credits (where applicable)
Other benefits (see text)
Electric Power Sales
Typical Range2
0
0
0.02
0.03
0.011
0.01
0.104
0.11
Notes:
1. Costs could include payment for the rights to the gas, or for the power sales contract, or to obtain an
equity position in the project: see section 4.1 tor more detail.
2. All extremes are unlikely simultaneously within the same project, so typical ranges are less than
possible span through adding components.
3. ROI may substitute for debt service - one will increase as the other decreases.
4. May include capacity payments as well as payments for kWh delivered.
PJG G640101A.AOW
16
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equal nominal, and so forth). However; the figure illustrates the variability (and, the lack of obvious
pattern) of landfill gas electrical generating facility capital costs, even allowing for the databases'
imperfections. The cost data and their scatter are undoubtedly explainable on the basis of site features
and variables discussed above but detailed analysis is necessarily outside the scope of this report.
4.3 Other Economic Issues
In addition to cost ranges, of interest to many energy users will be the range of required revenues, the
uncertainties of initial cost estimating, and constraints of economics on energy uses. Each of these
issues are discussed as follows.
4.3.1 Revenue requirement for electric power generation
The average power revenue required to justify an electric generation facility at a scale of I.OOOkW
(1 MW) or greater is regarded as being most typically about 5 to 8 or more cents per kWh3. Caveats are
that the equipment must operate with an acceptably low down time and few problems due to factors such
as energy equipment breakdowns or gas supply problems. There are obviously also sites where costs
combined with return criteria can result in sale prices both above and below this range.
4.3.2 Initial cost estimating
Accurate initial cost projections are difficult to develop, and initial cost underestimates—leading to unwise
projects—are frequently made (this problem is exacerbated when additional costs, such as for improved
gas cleanup, or equipment modifications, are found to be necessary as the project proceeds). Those
interested in developing economics for applications may wish to develop their initial data working with
others experienced with landfill gas energy applications. The intricacies of costing and implementing an
energy application are such that many—possibly most—of the smaller landfill owner/operators tend to
form partnerships and participate with entities already experienced in landfill gas energy applications, who
can provide help in stages throughout a project: examining use options, projecting economics, and
continuing through selecting and implementing the (presumably) best option.
4.3.3 Economic Impediments to energy applications
Landfill gas energy projects, including some of those to be described later in this report, can do well
economically. However, as can be inferred from tables and figure 1, low energy sale prices can
combine with high capital and operating costs at many sites. Individual landfills with substantial methane
generation often cannot find economic energy applications for the gas, and their energy potential is
wasted. Well-developed options for energy applications for smaller landfills and generation rates are also
lacking. Precise figures are not available but based on GAA (1988), a very small percentage (well under
10 percent) of landfills with outputs less than 200 cfm output (that could support 500 kW) appear to have
energy systems. Those means suggested for barrier reduction and facilitation of energy uses under less
than favorable circumstances are referred to in Section 6.
3 Authors' estimates; also discussed with Christine Nokn. Cogeneration and Independent Power Producer* Coalition, Washington,
D.C.
PJG G640101A.AOW 17
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Q (5000/kw)
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1000 2000 6000 lOjQGO
SIZE OP FACILITY (Kilowatts)
Figure T
COSTS PER KILOWATT VERSUS SIZE
For 38 facilities reporting capital costs in 1988 "Methane Recovery
From Landfill Yearbook* published by GAA
60.000
100.000
-------
5. CASE STUDIES
This section describes experiences with projects where landfill gas has been used in energy applications.
These include sjx projects in the U.S., references to four case studies in the U.K. (provided as
appendix K) and a discussion of other relevant literature. The case studies provide information
considered of most interest to readers (including, in. particular, potential energy users) such as how the
decision to implement the project was made, facility details, and particularly the energy equipment, and its
experienced performance and economics.
It should be recognized that limits exist on the amount of detail that can be presented for each case.
Information presented in various areas is intended to be illustrative and representative (rather than
comprehensive): it is hoped that It will nonetheless provide readers with useful overviews of each project's
experience.
5.1 Electric Power Generation and Space Heating Using Landfill Gas: Prince
George's County, Maryland
5.1.1 Introduction and general overview
The Brown Station Road Landfill is located in Prince George's County about 15 miles east-southeast of
downtown Washington, D.C. Gas from the landfill is used to supply both the electrical and the heating
needs of a County building complex and also electricity for export sale to the local utility. The energy
equipment comprises a landfill gas cleanup and pumping station, a 2-mile pipeline, three engine-
generators, and a boiler that supports the heating and hot water system of the 235,000-square-foot
County Correctional Complex (jail). The facility was engineered by the Maguire Group, Inc., of
Foxborough, Massachusetts. Curtis Engine of Baltimore, Maryland, the regional Waukesha Engine
distributor, was also heavily involved in subsequent operation of the project. A photograph of the engine-
generator set at the site (discussed later) is shown in figure 2.
General site and facility information is shown in table 4. The facility was wholly financed and is wholly
owned by Prince George's County. The County also receives all benefits; these include the operation
and management of the landfill gas extraction system, avoided costs for electrical power and heat for the
correctional facility, and revenues from power sales to the local utility, Potomac Electric Power Company
(PEPCO). The energy facility met more than 99 percent of the heat and electrical needs for the
correctional facility in the County's most recently ended fiscal year. The gross benefits to the County are
calculated to currently be running about $1.2 million per year.
5.1.2 History of project Implementation
Initial impetus for the Brown Station Road landfill energy project came from Prince George's County.
County staff recognized in the early 1980s that landfill gas emissions would need to be abated by a
landfill gas system and, that the gas would also represent an energy resource. Help from the Applied
Physics Laboratory at Johns Hopkins University, which was conducting landfill gas related investigations,
was obtained in 1982. The Laboratory used Brown Station Road waste placement data to develop
methane generation projections, and carried out preliminary economic projections; results showed that
sufficient gas would be available to support an energy recovery system, and that energy recovery had
favorable economics.
PJG G640101A.AOW 19
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'O
Figure 2 Waukesha Engine-Generator Sets at Brown Station Road Landfill. These engine generator sets
furnish nearly aN electrical needs of nearby correctional complex.
-------
TABLE 4. GENERAL FEATURES: BROWN STATION ROAD ENERGY FACILITY
Location: Brown Station Road, near Upper Marlboro, Prince George's County, Maryland (15 miles east of
Washington, D. C.)
Application: Electric generation and space heat. Electric and gas utilities are supplied to a 235,000-
square-fool County Correctional Complex; surplus electricity is sold to the utility company.
Energy equipment: Pumping station, 2-mile pipeline, three Waukesha engine-powered generators,
correctional complex space heating and hot water system
Equipment owned by: Prince Georges County
Equipment operated by: Curtis Engine
System design: Maguire Group
Landfill owner and operator: Prince George's County
Current tonnage in landfill: Approximately 4 million tons
Gas collection: County owned, operated by Curtis Engine
Maguire Group Inc., an architectural/engineering and planning firm (then known as CE Maguire) of
Foxboro, Massachusetts, was retained by the County to evaluate the technical and economic feasibility of
potential landfill gas uses. This study used the sustainable extraction rates established in the John
Hopkins report. Maguire's analysis examined the County energy demands and use options.
Based on probable methane availability, Maguire developed several different energy system options
involving variations on both equipment and timing of installation. In order of complexity and also rates of
methane use (increasing from A to F below) the options were
A. Heat and hot water to correctional complex
B. Heat, hot water and steam absorbtton air conditioning to correctional complex
C. Heat, hot water and power to correctional complex.
(Three generators, surplus power to PEPCO)
D. Heat, hot water and power to correctional complex
(Four generators, surplus power to PEPCO)
E. Heat, hot water and power to correctional complex
Heat, hot water to Upper Marlboro County Building Complex (UMC)
(Three generators, surplus power to PEPCO)
F. Heat, hot water and power to correctional complex
Heat, hot water and power to UMC
(Four generators, surplus power to PEPCO)
Comparison was on life cycle costs, revenue, and other bases. From these, the County selected
option C: to use landfill gas to directly supply the heating system of the correctional complex, and to fuel
gensets to provide power to the correctional complex and for export. The possible financing and
ownership options were also evaluated, and county ownership with municipal bond financing was
selected.
The energy system was implemented in a phased program beginning with initial design, and construction
of the landfill gas wells. This was followed by installation of the compressor building, gas transmission
PJG G640101A.AOW 21
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line, and engines. The energy system was completed concurrently with the County Correctional Complex,
the needs of which it was to supply. The first electricity was produced by the facility in July 1987.
Note that the negotiations with PEPCO, regarding sales price for cogenerated power and cost recovery
mechanisms for the two-way interconnect, were quite extensive (and were not completed until June 1990,
almost 3 years after the first power production).
TABLE 5. LANDFILL AND GAS SYSTEM CHARACTERISTICS: BROWN STATION ROAD
Landfill
Location: Off Brown Station Road, Prince George's County, 15 miles east of Washington, D.C.
Type: Mound Rll
Date Opened: 1960
Waste in Place: Approximately 4 million tons
Current Waste Fill Rate: 450,000 tons per year
Total Fill Area: 100 acres
Area Now Riled: 40 acres
Area of Extraction: 20 acres
Climate: Temperate, seasonal
Annual Rainfall: 45 inches
Daily and Intermediate Cover Soil: Various, as available
Rnal Cover Soil: 2 feet of day
Depth of Waste: Approximately 100 feet
Gas Extraction System
Type: Vertical wells—currently 29 active
Collection Unit Pipe Material: PVC
Lateral/Main Header Pipe Materials: HOPE and PVC
Location of Piping: Laterals and main header about 1 foot below surface
Collection System Details: Spacing between wells at 200 feet. Depths are 60 to 80 feet (or 60 to
80 percent of the waste depth)
Current Collection Rate: 695 cfm, or 1,000,000 cfd
Well Adjustment Protocol: Wells below 50 percent methane throttled, over 50 percent opened, as
required
Gas Analysis: 55 percent methane by volume
Gas Analysis Frequency: Six times per month
PJG G640101A.AOW 22
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5.1.3 Landfill and landfill gas system
Details of the landfill and landfill gas system are shown in table 5. The Brown Station Road Landfill is a
"mound fill," that is, it lies over the original soil surface in its "footprint." The landfill generates methane at
a rate in excess of current energy conversion needs; generation is expected to increase still further as the
filling continues at the current rate over the next 10 or more years.
One noteworthy aspect of the landfill's gas is Its content of halogenated organics. These are indicated by
a total chlorine content measured (in early tests by Waukesha, provided through Curtis Engine) at 200
micrograms per liter (jig/I). Waukesha states that these measured concentrations were among the
highest in Waukesha's experience and certainly are related to some initial engine problems (discussed
later).
Also worth mentioning are the gas system's past problems of a not-uncommon type associated with
differential landfill settlement which resulted in pipeline blockages from condensate pooling at low points.
Gas supply limitations due to blockage became so severe that much of the original system had to be
replaced in 1990; the extraction system has worked well since the 1990 repairs.
With the initial problems now corrected, methane and gas field monitoring and adjustment by Curtis
Engine, a gas stream of good quality (55+ percent methane) at a rate of up to 800 cfm is provided to the
energy facility with standard monitoring and adjustment procedures.
5.1.4 Energy facility and equipment
A schematic/block diagram of the facility's landfill gas processing and energy equipment is shown in
figure 3. For convenience, the energy system discussion covers (sequentially) the components of the
compressor station, the pipeline, the electrical generating station, and the heating and boiler system of
the correctional complex. A list of significant equipment items in each of these categories is presented in
table 6.
Compression station and Initial gas pretreatment. The current configuration has been modified
somewhat from its initial design (further discussion later). Gas from the collection system arrives at the
compression station at a pressure, determined by rate of energy usage, that at high gas use rates is
about -20 inches water gauge. A 1.500 gallon inline tank is used to intercept and collect condensate.
Gas then passes through moisture separators and a coalescing fitter. Gas pumping is by four oil-
lubricated compressors, located after the coalescing filters. These compressors are driven by smaller,
dedicated 1C engines, fueled by the processed landfill gas. Gas, pressurized to 100 psi, is then cooled to
36*F in an aftercooler from which further condensate is drained; the gas is then sent through a demister
and several further steps including fittrations and a desiccation step, to a dewpoint of approximately 20T
(see figure 3). After desiccation, gas is odorized for safety, using conventional natural gas odorant. A
stream of gas is extracted to fuel the compressor engines (described above), with the balance of the gas
being pumped through the pipeline (specifications shown in table 6) to the gensets and correctional
complex.
Engine-generator building. At the engine-generator building, after passing through further fitters, the
gas fuels a set of three Waukesha lean-bum engine powered gensets (table 6). These gensets are
providing almost all of the correctional complex's electrical needs (99 + percent, discussed later). To
reduce noise to the adjacent correctional complex and the surrounding area (which is populated), the
engine-generator building is double-walled.
Correctional complex heating and cooling. The rest of the landfill gas from the pipeline goes to fuel
the heating and hot water system of the correctional complex. This is a system based on two Cleaver-
Brooks 350 hp package boiler units of largely conventional design capable of operating on Number 2 fuel
oil, or pipeline natural gas. Adaptations enable operation on, and easy switchovers among, the fuels.
When operated on Number 2 oil, County records show that it would consume about 650,000 to 700,000
gallons annually.
PJG G640101A.AOW 23
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J
EXPORT TD
UTILITY
ELECTRIC
V
POWER
GENERATORS
\ EXHAUST TD
ATMOSPHERE
WAUKESHA
ENGINES
(3)
CORRECTIONAL COMPLEX:
HEATING, HOT WATER AND
ELECTRICAL NEEDS
CLEAN GAS FOR
PIPELINE
2 MILES
HEAT AND BOILERS
GAS FOR COMPRESSOR
LANDFILL GAS (LFG)
FROM COLLECTION
SYSTEM
CLFG),
1
CONDENSATE
COLLECTION
TANK
V\
ENGINES
FILTERS
IN
SERIES<2>
FILTERS
IN
SER1ESC2)
A
ENGINE POWERED
COMPRESSORS ON
SKIDS (4 SKIDS)
AFTERCOOLER
(LFG)
FILTER
DESICCATOR
CONDENSATE
Figure 3
Energy Facility At Brown Station Road Landfill
Simplified Block Diagram Showing Major Components
-------
TABLE 6. MAJOR EQUIPMENT ITEMS: BROWN STATION ROAD ENERGY FACILITY
Plant Inlet Section (Through Compressor)
Condensate collection on inlet header from gas collection system: 1,500-gallon fiberglass tank,
unbaffled
Compressor building (at landfill)
• Moisture separation: Mist pads manufactured by NECO Industrial Plastics
• Compressor skids (four in parallel): Sullaire screw compressors, model SA-581,
550dm; Waukesha F1197 GU engines (215hp) to drive compressors; Waukesha
model 04M heat exchanger for gas cooling
• Desiccator Henderson Engineering Model HP-2400 (uses Mrty-Dry proprietary
desiccant, dewpoint -20*F)
• nitration: Four finite element filters, 0.3 micron nominal cutoff, one before and three
after desiccator
• Further gas filtration for compressor engines: Nelson and Pall well filters, 0.3 micron
absolute cutoff
Pipeline and Energy Equipment
Pipeline: 2 miles long, 8-inch diameter, schedule 80, carbon steel, polyethylene coated and
cathodteally protected
Engine-generator building (double walled for sound suppression)
• Landfill gas prefiltratton before gensets: One Pall well 0.3 micron absolute cutoff, three
Nelson models 95802A
• Three Waukesha 5970 GL gensets, nominal rating 850 kW each. Engines modified
with chrome valve stems and guides, modified piston rings.
Correctional Complex Energy Equipment
• Heating System: Two Cleaver-Brooks fire tube package boilers, 350 hp rating. Heat
provided by hot water through coils; domestic hot water also provided.
While the landfill-gas-fueled energy facility meets most correctional complex needs, uninterrupted utility
supplies are obviously of utmost importance and the complex also has conventional utility hookups.
Performance and availability, Initial experience. This system was one of many landfill gas energy
projects that have encountered serious (but not insurmountable) problems, in this case on start-up. One
of the lean-bum Waukesha engines had operated for less than 500 hours in 1987 when, before the first
scheduled oil change, the engine seized. Examination of the seized engine showed evidence of serious
corrosion (paint peeled from interior crankcase parts, discoloration and serious deposit buildup on metal
surfaces). The engine had seized because deposit buildups had reduced piston clearances to zero; high
levels of oil contaminants were found.
The situation was reviewed by Curtis, Waukesha, and others. Landfill gas from the Brown Station Road
Landfill was confirmed to contain high levels of chlorinated organics (which as reviewed earlier, combust
to acid products that in turn cause damage). The facility's gas cleanup system (which had an initial
PJG G640101A.AOW 25
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design that appeared relatively conservative by standards of successful energy systems elsewhere) was
modified. The modifications, made with major input from Curtis, Waukesha and Maguire included
additional filtration and substitution of stainless for carbon steel piping in the plant sections before
desiccation, resulting in the current configuration.
Waukesha, through Curtis, also applied engine modifications developed to address landfill-gas-related
problems. These included hardened valve guides, chrome valve stems, modified piston rings and
elevated coolant temperatures. Operations were also modified, including more frequent oil checks and
changes.
Although satisfactory engine operation was obtained with these modifications, gas recovery system
problems associated with landfill subsidence also occurred during and after the initial engine problems; as
noted, gas supply inadequacies restricted operation and were only fully resolved with replacement of part
of the gas system in 1990.
Brown Station Road experience provides a good example of the severity of problems sometimes
encountered in energy conversion projects. Between July 1987 (when electricity was first generated) and
the present, losses of generated electric power, due to corrosion problems and associated retrofits, and
gas supply system problems, probably amounted to between one and two years of production at the
capacity that would have been expected without the problems. The Brown Station Road problems might
be considered "shakedown" in nature; such problems are generally most frequent in projects early on.
Performance after modifications. The combination of modifications to the gas cleanup train, the
engines, and the gas collection system resulted in an integrated system that has subsequently worked
very well.
Regarding electrical production, the engine-generators at full power produce a combined electrical power
output of approximately 2,300 kW (nameplate rating of 2,550 kW, less a 10 percent reduction for CO2
dilution with landfill gas). Averaged on-line availability of the three engines—when not limited by gas
recovery system problems—is estimated by Curtis to be about 92 percent. Power purchase records for
portions of 1988 (when the just-operational correctional complex was fully supplied by PEPCO utility
power during the cited engine and other difficulties) indicate that caseload demand at that time was
800 kW, increasing to an averaged rate of 1,400 kW in midsummer in the daytime peak hours (defined by
PEPCO as 8 hours per day). Available records are not in a form that permits precise determination of
ongoing electrical use by the correctional complex; indirect evidence (see 5.1.9) suggests it is 1,000 or
more kW caseload, and 1.700KW summertime peak (peak use period defined by PEPCO utility as
860 hours per year). Whatever the exact use, County electric billing records show that the complex's
power purchase from PEPCO was so low that the gensets unquestionably met more than 99 percent of
the complex's needs (the County calculates 99.9 percent tor the fiscal year ended June 30.1990; PEPCO
indicates the facility had purchased no power from October 1990 through June 1991 )4. The current
power supplv reliability (with corrosion and other problems now under control) would appear in large part
a function o! conservative design, for example, the high redundancy inherent in three parallel engine-
generators, tne four engine-compressor units at the compressor station, and the high degree of parallel
processing elsewhere in the system. The high level of on-line availability and reliability is also obviously a
function of the efforts of Curtis, the operating contractor.
Regarding the heating system, the County reports advantages with running the heating and boiler system
on landfill gas. The landfill-gas-fueled boilers are observed to be cleaner than oil-fueled boilers. Boilers
are inspected once a year; maintenance is by contract to Professional Boiler Works, Inc., and to date
very little maintenance has been needed. External fuel purchases are extremely tow; based on outside
fuel purchases and assumed annual displacement of the alternative use of 650,000 to 700.000 gallons of
Number 2 fuel oil (see 5.1.9). the County calculates that landfill gas provided 99.3 percent of the fuel for
heating and hot water needs in the fiscal year ending on June 30.1990.
Personal communication, David Leonard. PEPCO. July 1991.
PJG G640101A.AOW 26
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5.1.5 Environmental/emissions
The County reports only that the facility complies with all federal, state, and local emissions regulations.
The Brown Station Road landfill gas emissions that would otherwise occur through the surface of the fill
are also being abated satisfactorily. Note that the Brown Station Road landfill is 15 miles from downtown
Washington, D.C.; although the surrounding area is densely populated compared to most landfill sites, the
County reports no odor complaints.
5.1.6 Operation and maintenance
The Prince George's County Brown Station Road facility, with multiple gas end uses, is one of the more
complex U.S. facilities. The facility also has a more comprehensive maintenance contract than most,
through Curtis Engine. The County has four separate contracts with Curtis; contract components cover
maintenance of engine-generator sets, maintenance of the compressor station, overall operations, and
compressor building maintenance. (Certain of the contract payments to Curtis are tied to attaining
performance standards for the gensets.)
On-site energy equipment repairs and routine maintenance are performed by an on-site employee of
Curtis Engine. Additional support is given as needed; Curtis estimates that 16 labor hours per week are
spent on the energy equipment routine maintenance. Additional time and maintenance is spent on more
significant repairs including parts replacements and overhauls. Curtis not only operates and maintains
the energy equipment but also monitors and adjusts the gas field under existing contracts. Economic
aspects of operation and maintenance are discussed in section 5.1.7.
Some of the engine operation and maintenance modifications by Waukesha and Curtis for landfill gas
fueling are shown in table 7. These include higher oil and jacket water temperatures, frequent oil checks
for contaminants and metal content as an indicator of wear, and others as shown. (Engine part
modifications for landfill gas operation were discussed in 5.1.4.) Oil changes require two labor hours.
Some of the other maintenance tasks are destecant replacement and yearly replacement of the first finite
filter element. The elements of other landfill gas fuel filters have been analyzed by their manufacturers
but none have shown appreciable contamination in 2 years of operation.
To date, the gas transmission pipeline has needed no maintenance, which is a normal expectation with
pipelines but also would appear to attest to the effectiveness of gas moisture removal and cleanup in the
compressor station. One ongoing operational requirement for the pipeline is the flagging* and location
service to delineate the pipeline's location and prevent damage by excavation. This is a modest effort
performed by an organization specializing in such work.
The prison heating system is reported to require no more maintenance than a system operating on
pipeline gas. The operating history on landfill gas (since 1987) has, however, been relatively short; no
further information is available.
TABLE 7. ENGINE OPERATING CONDITIONS ON LANDFILL GAS: BROWN STATION ROAD
Jacket temperature range: 220 to 230T (104 to 110*C)
Oil temperature range: 190 to 195T (87 to 90*C)
Oil used: Mobil Pegasus 446, TBN over 7.0
Oil Analyses: Every 350 hours
Maximum oil change interval: 350 hours for 5790GL (Genset engines) and 500 hours for 1197
(compressor engines)
AOW
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5.1.7 Economics
A summary of the economic data is shown in table 5.6.5. and derivations (or origins) are discussed next.
Capital cost. The value which should be assigned to the capital cost of the facility is difficult to
determine. The proceeds of a $6.1 million County bond issue were used in financing but what part of the
bond proceeds was allocated to the initial construction is not dear (and how subsequent repair costs
should be treated is an additional issue for capital costs). An estimate of $6.1 million for capital cost is
used below; recognize, however, that this value is not certain.
Benefits. The gross cash benefits to Prince George's County consist of several components: the
avoided costs of electric power and oil that would otherwise be required for the correctional complex,
cash revenues from electric power export sales to PEPCO, and benefits from abatement of landfill gas
emissions that would otherwise be experienced without the landfill gas energy use. These benefits are
discussed next.
Although correctional facility power-use figures are not precise, available information does allow avoided
electric power costs to be estimated, as set forth later in section 5.1.9. Calculations suggest correctional
complex electrical savings of about $450.000 to $600,000 per year. An additional oil cost savings of
another $450,000 to $500,000 per year is implied by the avoidance of an estimated oil use of 650,000 to
700,000 gallons per year (see 5.1.9). Through the contracts with Curtis, the County also avoids the costs
it would otherwise experience for monitoring, adjustment, and repairs to the gas system, and blower
operations and maintenance. These gas system costs are estimated based on similar operations
elsewhere at about $50,000 per year.
Regarding sales to PEPCO note that, until 1990, power sales to the utility were based on fuel cost
avoidance only, which resulted in very low revenues to the County from the electric power sales. With the
improved generation reliability, and the resolution of other contractual issues (including mechanisms of
PEPCO's cost recovery for the two-way interconnect), the terms of the facility's cogenerated power sale
to PEPCO are much more favorable to the County; one improvement is a capacity payment (in addition to
the normal payments per kWh) for summer peak hour exports that runs near $0.lO/kWh. Data from the
County5 show sales of power to PEPCO in the range of $5,000 to $10,000 per month in early 1990 (until
.gas system problems were fully solved), but that are now increasing and closer to $20,000 per month.
These figures would suggest power revenue from power export sales at a present annual rate between
$200,000 to $300.000 per year.
As shown in table 8, the sum of the gross benefits, including both cash and "revenue equivalents'' to the
County, derived as above (without considering costs), would appear to be currently running between
$1,150,000 and $1,450,000 per year.
Costs and debits. The operating costs and debits comprise various service contracts with Curtis Engine,
a modest expense relating to the pipeline, and payments on bonds used to finance the facility. AH of
these expenses are discussed next.
Operating contract costs. As shown in tables, the operating contract costs are currently about
$400.000 per year (components were discussed briefly in section 5.1.6).
Pipeline Costs. The flagging1' service discussed earlier is stated to cost the County about $3,000 per
year.
5 Power sale and related records forwarded by Sheila Lanier. Prince George's County, to Don Augensttin. EMCON. June 1901.
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TABLE 8. ECONOMIC DATA: BROWN STATION ROAD LANDFILL GAS ENERGY FACILITY
Estimated capital investment: $6.1 million
Revenue, and avoided cost credits (thousands/year)
Electrical costs avoided $450-600
Heating fuel costs avoided $450-500
Electric sales to PEPCO $200-300
Gas System Credit JSP.
Total credits (approximate range) $1,150-1,450
Costs:
Contracts, Curtis Engine $399
Interest expense estimate (see text) 375-475
Pipeline-related (delineation) 3
Cost (approximate range) $800-900
Lower bound, operating cash flow - $1,150-900 « $250,000/yr
Upper bound, operating cash flow - $1.450-800 « $650,000/yr
Bond Interest costs. The facility was financed principally by a $6.1 million bond issue, marketed at the
extremely favorable interest rate of 5.4 percent. To reflect bond retirement and rollover to refinancing at
current rates, which could be 7 to 8 percent, and to reflect uncertainties in capital costs, interest charges
would more realistically be expected to be about $375,000 to $475,000 per year. Further discussion is
given in note 5.1.9.
Operating cash flow. The income less operating costs calculated and defined as above give rise to one
possible definition of "operating cash flow," which (as shown in table 8) might be between $250,000 and
$650,000 per year. A profit/loss calculation would require further assumptions in several areas, such as
depredation, and will not be attempted here; however, the current cash flow situation would appear
favorable for the County. If repairs and equipment .replacement costs do not exceed the operating cash
flow, the long-term cash flow and profit situation will remain favorable.
5.1.8 Discussion
General performance. After the "shakedown" phase in which problems with the gas system and engine
operation were resolved, the entire energy facility associated with the Brown Station Road landfill,
including a Degeneration facility and space heating, has been functioning well. The energy equipment
provides essentially all heat and power for the correctional complex, as was originally intended.
Increasing operating experience and use of preventive maintenance, such as more frequent oil checks
and changes, are reducing engine down time. The system is generating a positive cash flow, and the
long-term prospects appear favorable.
Plans. The County's capital improvement budget is currently extremely limited; however, with increasing
waste entering the landfill and expansion of the landfill gas system, more gas win become available. The
County is beginning to consider options for which incremental cost may be acceptable and the return to
PJG RR40101A AOW
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the County favorable. These include installing three more gensets, in extending the pipeline to serve
another County building complex, or both.
5.1.9 Calculation bases—energy use and financing
As stated in 5.1.4 and 5.1.6, available records do not allow correctional complex use rates to be
determined directly. It has been necessary to estimate various energy use and economic parameters
indirectly, and the estimates and their bases are set forth below.
Electrical power use and cost calculations. Regarding electrical power use, electrical billings over
intervals when the correctional complex was wholly supplied by PEPCO (in 1988) showed power use
shortly after startup to be about 800 kW caseload, up to a peak (noon to 8 p.m. weekdays) of 1,200 kW in
winter and 1,400 kW in summer. The estimated output of the gensets, based on discussions with Curtis
and other information, is 2,550 kW (nameplate) x 0.9 (correction for CO2 dilution, landfill gas operation) x
0.90 (service factor), which for a 730-hour average month gives an estimated total production of
1,500+MWh per month. The metering of correctional complex power use is not directly available:
however, the evidence suggests that its power use is substantially above 1988 rates. Power export sales
at full capacity by the facility of 300 to 600 MWh per month shown by 1990 records, combined with
generation of 1,500+MWh per month suggests time average correctional complex power use of
1,250+ kW in winter and 1,600+ kW in summer, and an annual time average near 1,400 kW. A possible
conservative minimum schedule for power use and cost is shown in table 9.
This reflects, however, an annual time average power use of only 1,150 kW. Power use estimates (by
the difference method above) suggest a possible annual time average use of as much as 1,400 kW and
power costs nearer $600,000 per year. A range of $450,000 to $600,000 for avoided electric power costs
has accordingly been used.
TABLE 9. POWER GENERATION AND REVENUE CALCULATIONS: BROWN STATION ROAD1
Summer Averages
Interval Duration hr/yr Use, kW $/kWh $/yr
Peak 860 1,600 $0.04918 $67,671
Int. Peak 860 1.400 $0.04286 $51,603
Off Peak 1,880 1,000 $0.02790 $52,452
Winter Averages
Peak 1,200 1.400 $0.04105 $68.964
Int. peak 1,200 1.200 $0.03576 $51,494
Off peak 2,760 900 $0.02322 $57,678
Demand charges
Summer $9£0/kW x estimated 1,700 kW peak use x 5 months • $80.750
Winter: $3.90/kW x estimated 1.500 kW peak use x 7 months - $40,950
Total annual estimated cost • $471,562
1. All rate information was provided by Fred Leonard of PEPCO.
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Heating oil use. The correctional complex's potential annual oil use would appear to be about 650,000
to 700,000 gallons per year (based on use rates while the landfill gas pipeline was not in operation).
Aside from price jumps occurring because of the Persian Gulf situation, before early 1991 the County had
been paying a price (with vendor markup) of about $0.60 per gallon in low-oil-use summer months,
ranging up to about $0.80 per gallon in winter. About 2/3 of the oil would be used in the winter. An
averaged overall cost of $0.70 per gallon multiplied by an estimated use of 650,000 to 700,000 gallons
per year leads to an estimated cost saving of $450,000 to 500,000 per year, as stated in the text.
Bond financing. The cost component for bond financing can be calculated in different ways that result in
different values for this cost. Based on an assumed capital cost of $6.1 million and a repayment schedule
with provisions for full bond retirement in 10 years, the cost of a $6.1 million bond issue is about $805.000
annually (Watts, 1987). This includes complete amortization of the bond principal over 10 years, which is
a higher than appropriate cost to include, since the energy facility's life will be much longer than the bond
term. Interest charges on $6.1 million at 5.4 percent would be $329,000 per year; however if initial bonds
at 5.4 percent are retired and refinanced ("rolled over) at a cost of 7 to 8 percent, bond interest cost will
be $375,000 to 475,000 per year as stated; the range is rather wide to also reflect uncertainties attaching
to the tiue capital cost.
5.2 Electricity Generation Using Cooper-Superior Engine at the Otay Landfill
5.2.1 Introduction and general overview
The Otay Landfill is located in Chula Vista, about 10 miles southeast of San Diego in San Diego County.
California. The energy facility at this site is owned by Pacific Energy (PEn). It uses a Cooper-Superior
engine-powered genset to generate electricity for sale to the San Diego Gas and Electric (SDG&E) grid.
The facility exports a net output of about 1.700 kW at an averaged sale price with all utility payments,
including capacity factored in, of around $0.09 cents/kWh, and typically obtains more than $1 million per
year in gross power sale revenue. General information on the site and facility is shown in table 10. A
photograph of the Cooper-Superior engine at the site (discussed in further detail later) is shown in
figure 4.
5.2.2 Otay landfill and landfill gas system
Details of the landfill and landfill gas collection system are listed in table 11. The Otay landfill is a large
canyon type fill, opened in 1966. PEn estimates that the landfill generates methane at a rate well beyond
the needs of a single genset. The fill is currently served by wells extracting from only part of its volume.
TABLE 10. ELECTRIC GENERATING FACILITY AT OTAY LANDFILL
Location: Off day Valley road, 10 miles southeast of San Diego, California
Nature of Application: Electric power generation and sale to San Diego Gas and Electric Grid
Energy Equipment: Single engine-generator set, net output range 1,700 to 1,750 kW, powered by
Cooper-Superior engine
Owner and operator of genset and auxiliary equipment: Pacific Energy
Landfill owner: San Diego County
Landfill operator: Herzog Contracting
Current tonnage in landfill: 6+ million tons
Gas collection system: Designed, owned, and operated by Pacific Energy
PJG G640101A.AOW
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Figure 4 Cooper-Superior Engine: Otay Landfill Electrical Generating Facility
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TABLE 11. LANDFILL AND GAS SYSTEM CHARACTERISTICS: OTAY
Landfill
Type: Canyon Fill
Date Opened: 1966
Waste in Place: 6 million + tons
Waste Rll Rate: 500,000 tons per year
Climate: Arid
Annual Rainfall: 10 inches
Final Cover Soil: Clay
Gas Extraction System
Type: Vertical wells
Number Active: 32 wells (early 1991)
Lateral/Main Header Pipe: Aboveground
Waste and Well Depth: Waste depth 90 to 150 feet; well depths approximately 75 percent of
waste depths. Extraction zone: Bottom 40 feet.
Current Collection Rate: 650-700 dm; 1,000,000 cfd (LFG)
Well Adjustment Protocol: To maximize Btu delivery to engine. Flow of wells over 50 percent
CH4 increased as needed; wells showing less than 50 percent ChU throttled.
Gas Analysis: 49-52 percent CH4 by volume (gas entering plant is analyzed by Daniels
automated gas chromatography system). Managed to maximize Btu extraction.
(PEn is now expanding the well system with the planned expansion of the energy conversion system to
two gensets.) As the gas system was configured as of March 1991 it was reported to function well with
standard well adjustment procedures to maximize total Btu delivery to the engine; these operating
procedures resulted in a methane content reported at 49 to 52 percent with a gas flow of 980,000 cubic
feet per day.
5.2.3 Gas preprocessing and energy plant equipment
A simplified block diagram of the facility's landfill gas processing and energy equipment is shown in
figure 5. A list of gas preprocessing equipment and energy equipment is presented in table 12. PEn has
also made available additional information on the Otay site; an energy equipment site plan is shown in
appendix G and further equipment details are listed in appendix H. (This additional information was kindly
provided when PEn made Otay available as a tour site for the Solid Waste Association of North America
Landfill Gas Meeting, San Diego, March 1991.)
Landfill gas handling and preprocessing. Gas enters the plant from the collection system at a
pressure of about -26 inches water gauge. It is initially cleansed of aerosols and particulates in a
knockout tank, which is followed by a demister. Motive power for gas extraction and its further pumping
through processing is provided by a two-stage, interceded reciprocating compressor, located after the
demister, which raises gas from the plant inlet pressure to about 90 psi, at the second stage outlet
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EXHAUST TO
A ATMOSPHERE
POWER
TD GRID
GENERATOR
~l
SENSOR
OUTPUT
COMPUTER)
ENGINE MONITORING
AND CONTROL
COOPER-SUPERIOR
ENGINE
SENSOR
OUTPUT
COMPUTER"
METHANE FLOW
DETERMINATION
L_
ORIFICE
ASSEMBLY
LANDFILL GAS
FROM COLLECTION
SYSTEM
KNOCKOUT
DRUM
-
DEMISTER
2 - STAGE
RECIPROCATING
COMPRESSOR
COALESING
FILTER
A
CONDENSATE
GAS
CHROMATOGRAPH
Figure 5
Electric Power Facility Based Dn
Cooper-Superior Engine At Dtay Landfill
Simplified Block Diagram Showing Major Components
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TABLE 12. DETAILS OF LANDFILL GAS PREPROCESSING EQUIPMENT AND ENGINE-
GENERATOR AT OTAY LANDFILL
Gas handling and preprocessing
Condensate knockout tanks: Before first stage compression, and interstage
Demister: Model SWRT-3, fabricated by MPF, Inc.
Compressor: Ariel two-stage reciprocating compressor; inlet -20 to -40 inches w.g.,
outlet90tolOOpsig
Filtration of compressed gas by King Tool model WW73T coalescing filter
Energy Equipment
Engine: Cooper-Superior 16SGTA, 16 cylinder, 900 rpm, turbocharged at 85-90 psig,
lean-bum, gross shaft power rating 1,900 kW
Generator: Kato model A23277000 1,875 kW; 4,160 volt; 3-phase
Substation: Transformer stepup from 4,160 to 12,000 volts; owned by PEn
Monitoring
Gas flow rate by orifice meter
Gas composition by Daniels gas chromatograph system
Methane flow to engine computed by Kaye data computer
Engine condition and output by appropriate sensors
Over-all monitoring system vended by FLW, Costa Mesa, California
(suitable for carburetion into the engine). Compressed gas at 90 psi then passes through a coalescing
fitter, and through a measuring station consisting of an orifice plate and appropriate pressure and other
sensors. The measuring station sensor outputs connect to a flow computing system, discussed below. A
small sidestream is withdrawn periodically, conditioned, and analyzed for methane content in a gas
chromatograph, also discussed below.
Engine. The engine is a Cooper-Superior lean-burn model 16SGTA. Other engine characteristics are
shown in table 12. The Superior engines were initially selected for earlier PEn sites because the
manufacturer, Superior Engine Division of Afax Industries, was willing to guarantee emission
performance. Satisfactory initial operation, spare parts inventory considerations, and increasing
familiarity with versions of the Superior engine led to their selection by PEn at subsequent sites including
Otay.
The engine is housed in a building with much of the auxiliary equipment (layout shown in appendix G).
Heat dissipation is a concern with such an engine enclosure; a large blower is used to circulate air
through the section of the building containing the engine to dissipate heat within the building and help cool
the engine. (The Otay site gets very hot in the summertime, increasing the heat dissipation concern.)
Other features of the engine and associated equipment are shown in table 12 and presented in
appendices G and H. The principal contractor involved in installing the facility was Equipment Associates
Company (EACO). EACO packaged the genset. Installation and construction was by Modular Products,
Inc., a former PEn subsidiary.
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Monitoring and Control. A feature of interest at Otay (as well as other PEn sites) is the automated
system that performs various monitoring and control functions. This monitoring and control system is
similar to those often used at remote engine sites but has additional features specific to landfill gas
operation. Landfill gas composition, as was noted earlier, is monitored by an automated gas sampling
and chromatography system (Daniels Corp), which samples and measures gas stream component
concentrations at predetermined intervals. Landfill gas flow is determined based on an orifice plate
system (PEn indicates that orifice meters are preferable to turbine-type meters, which tend to foul and
lose calibration frequently). The orifice system measures temperature, absolute pressure of the flowing
gas, and pressure drop across the orifice and delivers these data to a computer (Kaye Data); the
computer uses these and the gas composition data to calculate methane flows under standard conditions.
In addition to giving methane ftowrate information (which with power output allows engine efficiency to be
calculated) this sampling procedure detects changes that may indicate problems (such as oxygen in the
gas. which could indicate line leaks).
The system obtains indications of the "health" of the Cooper-Superior engine by measuring several
parameters; for example, it measures the cylinder head temperature of each cylinder (a tow temperature
would suggest that a cylinder was misfiring). Engine-threatening or other serious malfunctions activate an
automated shutdown sequence.
Data logging and processing for all of the above are performed by a minicomputer (Kaye Data), capable
of a range of processing and logging options. As an example of the system's capabilities, it can be
programmed to provide a readout of the previous 32 hours of engine performance based on engine
power output and other key operating parameters. This monitoring ability is one feature that allows PEn
to operate the system with low operator labor.
Performance/availability. Overall performance and availability have been excellent since the system's
startup in 1986. PEn states that the engine has typically been on-line more than 90 percent of the time in
years since startup in 1986. The down time, or the remainder of the time, is stated to be principally for
scheduled maintenance. Production was 93 percent and 97 percent of full rated capacity in 1989 and
1990, respectively.
The gross output of the genset, without considering parasitic loads, runs around 1,875 to 1.900 kW. The
parasitic toads, most notably the compressorAurbocharger at about 100 kW, but also blowers, lights, and
other uses, reduce output so that a net of 1.700 to 1.750 kW is exported to the grid. This net exported
output still represents a heat rate range stated by PEn to be between 12,000 and 14,000 Btus (higher
heating value) of landfill gas per kWh exported.
5.2.4 Environmental/emissions
Source tests are conducted on the engine consistent with the requirements set by the San Diego County
Air Pollution Control District The results of one such test are shown in table 13. The emissions of the
engine are within the limits set by the permit, also shown in table 13. A second engine would also be
permitted at its expected emission level and is being installed. The current air regulations do not allow a
third engine to be installed at this time.
5.2.5 Operation and maintenance
PEn's automated system for monitoring and controlling the engine and other key parameters (e.g., gas
flow, composition) typically allows the plant to be operated with one operator for a standard work week of
40 hours. The operators duties also include monitoring and adjusting the gas field. Additional staff
support may also be given as needed.
Maintenance items for the engine include weekly monitoring of oil for contaminants. The gas compressor
is inspected every 6 months. Oil is changed approximately every 2,000 engine operating hours, a task
that takes about 4 hours. Engine overhauls, consisting of upper and tower end, are performed
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TABLE 13. RESULTS OF SOURCE TEST ON COOPER-SUPERIOR ENGINE AT OTAY LANDFILL
Tests conducted by volatile organic compound testing, San Diego, California, October 20 to 27,1987.
Standard operating conditions, full load. Stack gas flow 5,680 scfm. Several runs averaged.
For reference: Exhaust O2 - 6.8 percent by volume, CO2 -13.4 percent by volume
Component Concentration in exhaust gas, ppm
NOx 370
CO 448
Non-Methane Hydrocarbons: 0.0769 to/bhp.hr
Allowable engine emissions limits, Otay landfill:
Component One engine Two enoines
NOx, Ib/yr 93,195 179,887
CO, Ib/yr 154,413 288,306
NMOC, Ib/yr 39.925 79,850
approximately every 8.000 hours. Other significant plant maintenance items are gas compressor
maintenance once per year, and various degrees of engine servicing at 500,1.000. and 5,000 hours, and
annually.
5.2.6 Revenue and cost Hems
Economic data made available for the Otay facility are summarized in table 14. The power sale contract
(under terms of a variant of the California Public Utility Commission's Interim Standard Offer Number 4)
with SDG&E is favorable. Although power sale payments actually vary with time and other factors, the
contract's features are such that when all utility payments are considered, the averaged per-kilowatt hour
price paid for a continuous, constant power stream sold to SDG&E would be about $0.09 cents per kWh.
This energy revenue includes capacity payments that are received by PEn in addition to the per kWh
payments (note that these contract terms were finalized in the mid-1980s and contracts available
currently would be less favorable). Thus, with power production typically over 90 percent of full-rated
capacity, the Otay facility revenue at an output of 1,700+ kW is high. Gross electric power sale revenues
in 1989 and 1990 were $1.2 million and $13 million, respectively. This revenue is distributed to several
participants; its allocation is not available but is distributed to royalty recipients, as well as PEn.
5.2.7 Discussion
Performance effects attributable to landfill gas. Engine power output is somewhat reduced compared
to nameplate rating or pipeline natural gas. The compression of landfill gas from atmospheric pressure to
the carburetton pressure of the lean-bum turbocharged engine (an energy demand not present with
pipeline gas) is a parasitic load probably reducing the net efficiency of the genset by several percentage
points.
Regarding engine life and wear. PEn maintenance precautions involving frequent oil checks, other
monitoring, other engine maintenance, and engine overhauls every 8,000 hours appear to prevent any
landfill-gas-contaminant problems from becoming severe.
PJG G640101A AOW
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TABLE 14. REVENUE AND OTHER ECONOMIC DATA: OTAY ENERGY FACILITY
Averaged payments per kWh, 1990: $0.09
Total capacity payments, 1990: $240,000
Total gross electric revenue, 1990: $1.3 million
Averaged payments per kWh, 1989: $0.089
Total capacity payments, 1989: $240,000
Total gross electric revenue, 1989: $1.2 million
Gas system capital investment (excluding energy plant): $300,000
Estimated capital investment for energy equipment: Not available (confidential)
Lessons (earned and other comments. PEn did not identify any issues that could be categorized as
"lessons learned" from its Otay site. This is not unexpected since lessons learned from PEn's operation
at other sites were presumably applied at Otay to forestall problems. PEn staff did point out, however,
that emission standards changes, including those occurring "after the fact" of permitting and start-up, are
posing serious uncertainties and cost impediments to projects such as Otay; such costs must be borne by
cogenerators like PEn since there are no means for passing them through to power purchasers.
Plans. Because landfill gas is available and the permit allows for it, PEn is installing a second genset at
Otay. (Note added as of September 1991: the installation has now been completed.) It would consider a
third, H gas proved available and the permit could be modified to allow it.
Summary. PEn is a significant operator of landfill-gas-fueled electrical generating facilities. It has
developed site selection criteria and operational practices that appear to serve well. Economic
performance appears to have been good.
5.3 Electric Power Generation Using Waukesha Engines at the Marina Landfill
5.3.1 Introduction and general overview
The Marina Landfill is on Del Monte Road 1 mile south of California State Highway 1 in Marina, California.
The facility at the site employs two Waukesha-engine-powered gensets for electric power generation and
sale to the Pacific Gas and Electric Company (PG&E) grid. The gensets generate a net total of
approximately 1,150 kW for export to PG&E A photograph of the trailers housing the gensets is shown in
figure 6.
With initial genset startup in 1983, this was one of the first landfill gas-to-energy projects to operate In the
United States. General information on the site is summarized in table 15. The initial capital investment in
the system, exclusive of the extraction system was about $1.3 million in 1983 dollars. Gross revenue
from electric power sales within the past few years, including capacity payments, has typically been about
$360,000 per year.
Current operating arrangements are also indicated in table 15. The Monterey Regional Waste
Management District (MRWMD) owns and operates the engines, receiving the profit (or any potential
toss) from engine operation. The Monterey Landfill Gas Corporation (MLGC) operates the gas system,
p irz r5
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Figures
Marina Landf HI
. Each trailer
bed.
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TABLE 15. ELECTRIC GENERATION AT THE MARINA LANDFILL
Site: Marina, Monterey County, California
Nature of application: Electric power generation and sale to grid.
Energy equipment: Engine-generator sets powered by Waukesha Engines, system designed by
Perennial Energy
Owner and operator of Energy Equipment: Monterey Regional Waste Management District
Startup dates of gensets: December 1983 (first) and February 1984 (second)
Landfill Owner: Monterey Regional Waste Management District
Current tonnage in landfill: 4 million tons in early 1991
Rll rate: 850 tons/day.
Gas collection system: Designed by EMCON; owned by and operation/monitoring by Monterey Landfill
Gas Corporation (MLGC), a subsidiary of EMCON Associates
with additional gas system operating assistance being provided by MRWMD staff. The MRWMD's
benefits come from power revenue, landfill gas collection, and consequent emission abatement. The
MLGC's benefits come from a royalty on net power sales of $0.00667 per kWh and tax credits on the
delivered gas.
5.3.2 History of project
Two factors were particularly helpful in initiating this project. The MRWMD directors and staff were aware
early that landfill gas represented a potential source of energy and revenue for the district. EMCON
Associates (EMCON), the districts consultant, also had early involvement and background in landfill gas
energy issues. A complete project history is available because of the principals' documentation of the
project in the technical literature. Two references (Myers, 1987, and Van Heuit and Pacey, 1986) present
the MRWMD and EMCON's perspective on details of the project's implementation and subsequent
experience to 1987. The major steps in the implementation of the project included the following.
Initial steps:
1. An initial feasibility study was commissioned by the MRWMD and carried out by
EMCON in 1981. This study (in conjunction with gas extraction tests discussed next)
showed that landfill gas energy recovery was likely to be feasible and profitable. This
study was supported by the MRWMD (67 percent) and PG&E (33 percent). The PG&E
utility was interested at the time in augmenting electric generating capacity in its
service area (whether by itself or through independent suppliers).
2. Gas extraction tests were conducted, the major ones being a two-well test that had
been conducted in 1977 (preceding the study discussed above) and another two-wen
test completed between September 9 and October 16,1981. These tests, as well as
the projections of a gas generation model (see Van Heuit, 1987; similar to models
discussed in EMCON, 1982) indicated that sufficient gas was available to allow
economic electric power generation. All extraction tests and gas generation
projections were performed by EMCON.
3. EMCON suggested—with concurrence from PG&E—that using the gas to fuel electric
power generation for sale to PG&E was the best alternative.
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(Note: The further negotiating steps, with engine suppliers, exemplify complexities that can be
encountered in attempts to implement an energy system. The brief summaries presented below that
suggest their complexity, and additional detail can be found in Myers, 1987.)
4. Negotiations for an energy conversion system proceeded initially with Engine Power
Company of Stockton, a large, well-established, and experienced vendor of engine-
generator sets. Engine Power considered including financing with the complete
package. In 1982, however, Engine Power elected to terminate negotiation due to
financing considerations.
5. American Mobile Power was the next potential vendor of a complete package. It
obtained an Authority to Construct from the local air quality district, and a power sales
contract from PG&E during this negotiation. American Mobile Power could not,
however, obtain the required financing. It terminated negotiations shortly thereafter.
6. The next step, undertaken to reconfirm the basis for the project and reassure potential
participants, including those providing project financing, was a longer term gas test
performed by EMCON in 1983, with sixteen 50-foot-deep wells to fuel a portable
engine. These tests again showed the availability of adequate gas.
7. Proposals to the MRWMD were concurrently considered for energy packages and
financing, which were made by Cambrian Energy Systems (Pacific Lighting) and Gas
Recovery Systems (Genstar). A proposal including financing was also made by
Palmer Capital (Palmer).
8. After extended negotiation, Palmer was selected as a partner. Perennial Energy, now
of West Plains, Missouri, also offered the package judged best, to design, install, and
maintain two trailer-mounted gensets powered by Waukesha 12-cylinder. 7,040 cubic-
inch engines, for an initial cost of $1,300,000.
9. Financing for the energy facility was arranged by Palmer, in part through the formation
by individual investors of the Marina Landfill Gas Corporation (MLGC), and in part
through a loan from the Bank of New England. The MRWMD leased the gas rights to
MLGC in exchange for royalties of at least 12.5 percent of gross power sales to PG&E.
10. Further emission-related issues were resolved in order to obtain a permit to operate
from the Monterey Bay Unified Air Pollution Control District.
Steps 1 through 10 resulted in the installation and operation of the first genset in December 1983, and the
second in February 1984. The installation can be considered the result of persistence by technically
aware participants (though H cannot be said to be the result of experience, since no one had experience
at that time).
Further occurrences after startup are of historical Interest, and will be referred to in the later economic
discussion:
11. In 1986, largely due to a decline in PG&E power payments, but also because of tax law
changes, Palmer Capital donated Its stock and sold the gensets to the MRWMD for
$500,000. MLGC retained ownership of the gas and gas system (through 2001). As
owner of the gensets and PG&E power-sales contract, the MRWMD now receives
revenue from the sale of electricity: royalties are paid "to MLGC. As a further
informational note to the sequence of steps above, MLGC was purchased by EMCON
in 1988 (for $200,000).
5.3.3 Landfill and landfill gas extraction system
Details of the landfill and landfill gas system are given in table 16. The Marina Landfill is a large landfill,
termed an "area fill" type by the MRWMD (it could also be termed a cut and fill), in operation since 1966.
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It had received about 4 million tons of predominantly residential municipal waste by early 1991. The
depth of fill in areas from which gas is extracted ranges up to 90 feet.
TABLE 16. LANDFILL AND GAS SYSTEM CHARACTERISTICS: MARINA
Landfill
Location: North of Marina, in Monterey County, California; on Del Monte Road, 1 mile
south of California Highway 1
Type: Area Fill
Date Opened: 1966
Waste in Place: 4 million tons
Waste Fill Rate: 260,000 tons per year
Total Fill Area: 490 acres
Area Now Filled: 90 acres
Climate: Mediterranean
Annual Rainfall: 11 inches
Daily Cover Soil: Sand/silt
Intermediate Cover Soil: Sand/silt
Rnal Cover Soil: Sand/silt with 1 foot of clay
Gas Extraction System
Type: Module 1 - vertical wells. Module 2 - horizontal trenches
Number Active Collection Units: Module 1-12 vertical wells; Module 2 - 7 horizontal
trenches, Module 3 - none
Collection Unit Piping: PVC
Lateral/Main Header Pipe Material: PVC, aboveground
Collection System Details:
Vertical wells: 18-inch diameter, 40-50 feet deep, permeable material and
slotted pipe below 20 feet, bentonite seal at top of permeable material and at
surface
Horizontal trenches: 2 feet deep by 3 feet wide backfilled with 11/2 inch
gravel, embedding 6 inches PVC solid pipe, no seal at Joint (gas enters loose
Joint), 6-ounce geotextile cap over gravel.
• Pipe slope at minimum of 2 percent
Current Collection Rate: 580 cfm (LFG), or 850,000 cfd (LFG)
Adjustment Protocol: Keep methane concentration at 55 percent + since only about half
of estimated gas availability is extracted.
Gas Analysis: Methane analysis by portable thermal conductivity based gas analyzer
-------
The initially installed portion of the landfill gas system consists of 16 vertical extraction wells (first used for
tests as described in Van Heuit and Pacey, 1987). Horizontal trenches have been installed subsequently
as newer areas are constructed. The MRWMD has installed seven horizontal trenches in Module 2 and
two horizontal trenches in the lower portion of Module 3. The extraction well system is maintained by
MLGC, with assistance from the MRWMD.
The Marina landfill generates methane at a rate in excess of genset needs. Extant wells and connected
horizontal trenches could provide significantly more gas than is required for the engines; in general, the
field functions well, with few adjustments. Some wells are ten wide open; wells yielding less than
50 percent methane, as occurs occasionally, are throttled back. The few other adjustments include
periodic replacement of flex hoses and resloping of aboveground gas lines so that condensate drains
properly. Condensate accumulation problems have occurred from time to time, and further condensate
traps are being installed in response to needs.
5.3.4 Gas preprocessing and energy plant equipment
A simplified block diagram for the energy facility is shown in figure 7. Major gas preprocessing equipment
and energy equipment items are listed in table 17.
Landfill gas handling and preprocessing. The features of the gas collection system were noted above.
The equipment for landfill gas handling and preprocessing at Marina consists solely of a fiber filter
medium (size cutoff not available) in a small housing, and two small Hauck blowers, one for each engine.
The blowers and filter were engineered by Perennial Energy. This is considered very limited processing,
based on practices elsewhere.
Engines. Each of the two gensets is powered by a Waukesha model L7042GU 12-cylinder engine. The
noteworthy feature of this engine model is that it is naturally aspirated. As discussed in section 3, this
means that the engine is carbureted at a near stoichiometric fuel-to-air ratio (the mix can be very slightly
fuel rich) and that the fuel-air mix enters engine cylinders at near atmospheric pressure. This contrasts
with the use of lean-bum engines, which are turbocharged, at most other U.S. sites where landfill gas is
used to power 1C engines. Further characteristics of the engines are shown in table 17.
The gensets are housed in two trailers, as originally designed by Perennial Energy. The trailer roofs were
designed to be removable for maintenance. The trailers were originally mounted on railroad ties, but
these were replaced in 1985 with a steel frame after vibration and settlement problems attributable to the
railroad tie mounting occurred.
A catalytic converter, mounted on the outside of the trailer, is used to reduce NOX, CO, and NMOCs in the
engine exhaust. This catalyst (performance is discussed later), is a 3-way type very similar to that used
for automotive exhaust purification. After trials with various forms of catalyst, the MRWMD has settled on
a Riley-Beard catalyst on a bead-type support.
Performance/availability Issues. Over-all performance and availability have been good since the first
genset was installed in 1983. The MRWMD states that an average availability of more than 80 percent
was obtained for the first 3 years of operation (Myers, 1987). One way in which the genset service factor
may be calculated is to divide the actual yearly power output sold to PG&E by the number of kilowatts
that could potentially be obtained at 1,150 kW with no downtime in a full year. Service factors calculated
on this basis (for this report) from yearly kilowatt totals were 81 percent in 1987,89 percent in 1988, and
82 percent in 1989 (the service factors might be slightly different if calculated on run time). The MRWMD
has calculated a service factor, based on run time, of 80.4 percent for 1990. The most serious outages
were a bearing failure in 1985, believed to be caused by the inadequacies of the railroad tie supports for
the genset trailers, and an outage in 1990, not related to any fundamental genset problem in 1990, due to
a supplier shipment of the wrong maintenance replacement parts.
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POWER
TO
GRID
GENERATOR
CA1ALYTIC
CONVERTER
EXHAUST
TO
ATMOSPHERE
VAUKESHA
ENGINECS)
LANDFH L
GAS FKJM
COLLECTION
SYSTEM
BLOWER
CONDENSATE
Figure 7
Electric Facility At Marina Landfill
Simplified Block Diagram Showing Major Components
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TABLE 17. DETAILS OF LANDFILL GAS PREPROCESSING EQUIPMENT AND ENGINE-
GENERATOR SETS AT MARINA LANDFILL
Gas Preprocessing
Blowers: Two Hauck, 4 hp, model TBA-16-3-T-1 (one per engine)
Custom filter unit: Cartridges in 2-foot diameter by 4-foot high housing; designed by Perennial
Energy, West Plains, Missouri
Energy Equipment
Engines: Waukesha L7042 GU engines, naturally aspirated
Generators: Reliance model VHP 7100G. Approximate maximum output 650 kW,
normal output range 560 to 600 kW
Engine operation and maintenance data:
• Oil used is Mobil Pegasus 446 high alkalinity, 850 hours between changes
• Maintained 1983-88 by outside contractors, 1988 on by MRWMD
• Catalyst system: Riley-Beard catalyst. Catalyst in annular bed between inner
and out cylinders; 4 inch catalyst bed depth, area of catalyst bed
approximately 12 square feet
Other than bearing failure and spare parts problems, the 15 to 20 percent downtime has been for routine
maintenance and a variety of other causes worth noting briefly. The engines have tended to overheat
when ambient temperatures are over 70*F and winds are blowing from east to west (counter to the
prevailing wind direction, which means the radiator is on the lee side). Some fatigue-related engine
problems are said by Marina staff to be developing. The closeness of a hot exhaust pipe to the cylinder
head was at one point a source of problems, as was the noted original mounting of the trailer enclosures
on support beds of railroad ties. Some of the problems, as well as repair difficulties, appear to be the
result of the deliberate decision to save money on the genset design. Given the reasonable on-line
performance to date, however, it is not clear that spending more money initially on the gensets would
have been highly cost effective.
Fuel efficiency. The calculation of engine fuel efficiency at Marina presents some uncertainties. (With a
more than adequate gas supply—and a facility that is generator limited—there is currently no incentive to
maximize, or even closely determine, the fuel efficiency of the engines, which are running at less than
their greatest possible output.) One uncertainty that can be mentioned is just how much fuel is actually
entering the cylinder on each stroke. Waukesha expects that the heat rate of this particular engine on
pipeline natural gas at full power would be near 10,745 Btu/kWh shaft power6. It can only be said that, by
various indicators (which are approximate), the Marina engines' fuel use would appear to be very
substantially higher, when expressed as Btu/kWh sold to PG&E. This would in part reflect the expected
generator inefficiency in converting engine shaft power to electric power.
Catalyst. Catalyst We, even with frequent dust removal and washing, has, until recently been short,
about 3 months; catalyst replacement • has therefore represented a significant expense. Catalyst
6 Ptnoral communication, Water PonM, Wautosha Engine Division, Wauta ha. Wl. June 1M1.
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problems are considered to be landfill-gas specific, and generally due to attack from small quantities of
HCI and HF formed during combustion (section 2). Recent changes to a higher alkalinity engine oil
appear to be substantially increasing catalyst life. One additional problem identified by the operator is
that under certain operating conditions, the catalyst temperature can increase, inactivating the catalyst
(apparently by sintering). The operator states that, with the existing catalyst temperature sensing
arrangement, damage appears to be done by the time the temperature rise is noted.
Specifics of catalyst performance in reducing emissions are presented next.
5.3.5 Environmental/emissions
The genset engines are emission tested consistent with requirements set by the Monterey Bay Unified Air
Pollution Control District. Available results from three exhaust emissions tests are shown in table 18;
these test results illustrate aspects of catalyst performance.
The emissions of an engine with an exhaust catalyst are a function of (1) the functional ability of the
catalyst to reduce NOX and oxidize other exhaust gas components and (2) the operating parameters,
particularly carburetion, of the engine. Ideally, the engine carburetion will be close to stoichtometric, with
just enough air to bum the fuel. The catalyst will cause the reducing gases (CO and NMHCs) in the
exhaust to reduce NOX to N2, leading to substantial reduction of the reducing gases and NOX in the
exhaust gas. The emission performance of the engine in this (rather ideal) case can be good; without
going into detail, note that the results (shown in table 18) of the first engine test (September 12,1989)
show pollutant emissions below any existing California or U.S. standards. On the other hand, deviation of
the air/fuel mix from stotehtometric can lead to formation of more NOX than can be reduced or more
reducing compounds than can be oxidized; any of these conditions, or catalyst inactivation (which has
TABLE 18. SUMMARY RESULTS: EMISSIONS TESTS ON MARINA ENGINES
(Output at 560 kW, average of three 1-hour tests for each date shown)
Exhaust component ppmv GnV Measured Permitted
(as emitted) bhphr to/hr Ib/hr1
September 12.1989. engine M2
NOx 10 0.04 0.07 3.12
CO 78 0.21 0.34 11.45
TNMHC <10 <0.01 0.02 3.12
September 20.1990. engine M2
NOx 2.5 0.01 0.02 3.12
CO 518 0.6 2.52 11.45
TNMHC <10 <0.01 <0.01 3.12
October 20.1990. engine M1
NOx
CO
TNMHC
25
2211
0.02
0.13
7.31
0.01
0.22
12.10
0.02
3.12
11.45
3.12
1. Assumed as half of total permitted emission limits for two engines operating simultaneously
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been a major problem at Marina), can cause the emissions to rise to unacceptable levels. This is
illustrated by the last test of engine M1 on October 20,1990, which shows elevated CO levels that might
be due to an overly fuel-rich carburetion condition. (Note that only one tested emission level in table 18
can be considered to exceed permit condition, and that only slightly: October 20,1990, for CO.)
As engine loads increase, at generator outputs above 600 kW, tests have also shown (detail omitted) that
emission levels tend to increase significantly, even with the catalyst. Thus emissions have sometimes
been limiting facility electric output; the degree of limitation will decrease if catalyst performance can be
improved. The permit to operate currently limits each generator's output to 640 kW.
5.3.6 Economics
As a preface to a discussion of economics, some background on ownership should be noted. At the
original purchase price of $1.3 million and with initial financial arrangements, MLGC's break-even level for
power sale to PG&E was about 4 cents per kWh (total of all utility payments including those for capacity,
averaged per kWh). The power sale contract (which had, among other features, a variable price
component relating to the purchase price PG&E must pay for oil/gas fuel) was such that power purchase
prices could and did fall below this in 1986. The system was at that point transferred to the MRWMD for
$500,000 (Myers, 1987). With this transition, the arrangement changed from one in which the MRWMD
received a royalty of 12.5 percent on gross power sales, with minimal risk, to one in which the MRWMO
operated the system and bore the entire responsibility for profit and loss. The power sale royalties to the
MRWMD, by years before the sale, were $33,084 in 1983 to 1984; $93,989 in 1984 to 1985; and $44,672
in 1986. The revenues beginning in 1987 (which are best expressed as net of various expenses, and with
qualifiers), after the sale, are discussed below.
Revenues from sale of electric power to PG&E consist of payments that vary on a price schedule by time
of day for kilowatt hours delivered, and also a capacity payment with this particular contract (the capacity
payment reflecting, in essence, savings relating to generating capacity the utility does not need to build).
Appendix I shows a typical schedule of sale prices per kilowatt hour for specified time periods, ranging
from $0.028 to $0.034 per kilowatt hour in mid-1990. One feature of the contract to note is that PG&E
may elect not to buy power for up to 600 hours within any given year. The MRWMD continues, however,
to operate the engines and provides power to the PG&E grid, because of the environmental benefits at
Marina, even when PG&E elects not to pay. The capacity payment, which reflects the higher value of
generated power in meeting needs at times of high demand, is important and normally provides a large
portion (about 35 percent) of the total gross electric revenue; it amounts to additional revenue in the
range of $0.015/kWh. Capacity payments (by calendar year) at Marina were $138,000; $140,000;
$130,000; and $13,700 in 1987 through 1990.
A problem with maintenance spare parts and down time in 1990 caused most of the 1990 capacity
payment to be deferred until certain probationary, conditions imposed by PG&E were met; these
conditions were in fact met and the 1990 capacity payment was collected in 1991 (in addition to the
normal 1991 capacity payment that was earned in 1991).
Table 19, derived from figures provided by Marina, shows gross electric revenues and operating
expenses for the three Marina fiscal years beginning In the year July 1,1987, to June 30,1988. (1990 to
1991 figures are not available; the 1990 to 1991 revenue would be low as noted because of the deferral
of capacity payment; this is not a permanent problem). The operating expenses include factors such as
operating labor, maintenance, and royalties, but exclude capital-related charges such as interest on debt
and depreciation. The table does not include a one-time tax payment of $82,000 that was peculiar to
Marina's circumstances and would not be a normal expense. The operating revenue for the MRWMD is
calculated in table 19 as the difference between the gross revenue and operating expenses. The average
operating revenue, as defined above for the three typical MRWMD fiscal years 1987 to 1988,1988 to
1989, and 1989 to 1990, has been near $166,000 per year. It is very important to note that this operating
revenue specifically excludes the debits that would be due to financing charges, and depreciation
necessary to reflect the eventual need for equipment replacement.
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TABLE 19. ECONOMIC DATA FOR MARINA LANDFILL GAS ELECTRIC GENERATION FACILITY
Initial capital cost of facility (1983): $1,300,000
Purchase price paid for facility by MRWMD in 1986: $500,000
Typical" per kWh price schedule for power sale: See appendix I
Calculation of operating revenue (see text) by year of operation:
Year
Gross revenue
Less:
GASCO royalties
Repairs, maintenance
Salaries/fringes
Misc outlays
Net Operating Income
1987-88
$369,328
$56,125
$126,909
$6,000
$4.081
$176,213
1988-89
$360,825
$55,349
$85,672
$36,000
$13.407
$170,468
1989-90
$360,927
$50,755
$87,080
$45,000
$25.265
$152,827
MRWMD has paid off all capital costs with revenues, and now owns the system free and clear. It
receives the benefit of landfill methane emission abatement in those areas where gas is being extracted.
While the benefits are obvious and the MRWMD nets income, its capital cost has been well below the
typical capital cost for similar equipment. Revenues would need to be higher than at Marina to assure
acceptable economics if the equipment cost were more typical. Some further discussion of economic
issues is presented in 5.3.8.
5.3.7 Operation and maintenance
Supply and other costs were listed above. The naturally aspirated engines can operate with only
moderate attention. Operation and maintenance labor-hours are estimated at about 40 hours per week.
These labor needs actually vary, given that a team of maintenance workers may be needed on occasion,
while at other times very little operator attention may be needed. Parts cited as routine maintenance
needs are head gaskets and cylinder heads. Marina staff rebuild the cylinder heads on site.
5.3.8 Discussion
Performance effects attributable to landfill gas. The impact of using landfill gas on the performance of
the system, compared to what might be expected with the same system's performance on natural gas,
seems minor. The Waukesha L7042GU engines would be expected to produce 1,173 horsepower, or
875 kW on pipeline gas.7 Even allowing for an engine shaft power toss of 10 percent, due to dilution by
C02, maximum engine shaft power output on landfill gas could still be expected to be about 790 kW. The
generators however limit each gensefs output to 600 kW, so COa dilution is not the limiting factor on
power.
Given the problems encountered at other sites, and the very limited gas preprocessing at Marina, the
absence of engine problems attributable to landfill gas contaminants at Marina over an 8-year period is
notable. None of the problems mentioned earlier with the engines/gensets relate specifically to
contaminants. The Waukesha factory representative indicates that operation and maintenance of the
Personal communication. Waltor PonM, WaukMha Engint Division. Waukasha, Wl. June 1901
o ir; r5(
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engines should be close to identical at their somewhat reduced load compared to full toad operation,
other things being equal7. It can be speculated that the lack of problems could be attributable to
cleanliness of gas at the Marina she, or possibly some feature of stoichiometric-bum naturally aspirated
engines that renders them less susceptible to landfill-gas-contaminant related problems.
Catalyst performance Issues. Catalysts' performance has in general been poor when they have been
used with landfill gas fueled stotehtometric bum 1C engines in the past (Jansen, 1986). Low levels of HCI
and HF combustion products typically attack catalysts and support, causing malfunction. This was the
case until recently at Marina, as the catalyst bed had to be cleaned about once each month, and the
catalyst had an extremely short service life (very rapid breakdown) versus that with normal natural gas
applications. The adoption of a high-alkalinity oil whose ash is reported to coat the catalyst appears to be
benefitting catalyst life (as might be expected chemically). As of the site visit, the most recent batch of
catalyst had been performing well, with only limited dust removal, for more than 7 months. This
performance, if sustainable, would reduce catalyst related costs and help make stofchiometric bum
approaches such as are used at Marina more attractive.
As a summary comment on the potential of catalysts, the Marina results suggest promise for their use in
reducing emissions of naturally aspirated stoichiometric bum engines. Their successful application would
enable greater use of these naturally aspirated engines with their attendant operating simplicity. As seen
at Marina, however, the various problems with catalyst attack, mixture control, and other areas are not yet
completely solved.
Economic Issues. As noted in 5.3.6 the Marina facility generates a positive cash flow, but It was
acquired by the MRWMD for $500,000, a capital cost that was about 40 percent of the initial market cost.
By way of comparison, costs of a brand-new .facility with characteristics similar to the Marina facility can
be roughly estimated to be between $1.5 and $2.5 million, or roughly $1,000 to 2,000/kW (excluding gas
extraction). Depending on depreciation figures and financing costs (which are to some extent a matter of
judgement), a new facility in this cost range would be losing a moderate amount of money by selling
power to the grid with the actual power sale arrangement. The basic, overall import is that Marina, with
its existing revenue structure, would not be implemented today because of economics. Facility expansion
is precluded by economics and also emission constraints although the gas is available.
Lessons learned and other observations. Marina staff note that access to the current trailer is difficult
for certain types of repair and maintenance. The lack of "as-built" drawings has also posed a problem in
some areas, notably generator repair. Relating to overheating problems, Marina staff have suggested
that these could have been reduced M roof-mounted radiators had been used.
Plans. With recent improvements in catalyst performance, a third engine installation might be permitted
by the Air Pollution Control District; the gas is available and the MRWMD would attempt to install a third
engine if it could obtain a satisfactory power sale agreement. PG&E now has a surplus of generating
capacity, however, as well as low-cost power being vended to its grid. The chances of obtaining an
agreement providing satisfactorily high power revenue in the near term appear small. (The PG&E utility
does, however, anticipate a need for additional capacity later in the 1990s,)
5.4 Electric Power Generation Using Gas Turbines at Sycamore Canyon Landfill
4
5.4.1 Introduction and general overview
Sycamore Canyon landfill is located near San Diego, California. The facility at this site uses two Solar
Saturn recuperated gas turbines to generate a total of slightly more than 1,300 kW (net) for export sale to
the San Diego Gas and Electric grid. As of the site visit (March 1991) the facility was owned and
operated by Solar Turbines (Solar). A photograph of the building housing the turbine generators is shown
as figure 8.
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Figure 8 Sycamore Canyon Electrical Generation FadMy: Building Houses two solar gas turbines, and
associated generators.
-------
General site information is summarized in table 20. The turbine generating system has been operating
since 1989. Solar states that capital investment for this system was about $4 million; gross revenues
from electric sales are currently running at about $650,000 per year. Solar operates and has
maintenance and profit-and-toss responsibility for the generating plant. Solar also operates the landfill
gas system. San Diego County has overall responsibility for operation of the landfill.
Further specifications and details on the energy application and operations at this site follow, beginning
with the history of implementation.
5.4.2 History of system Implementation
Solar staff indicated that motivating forces to embark on this project included (1) an acceptable projected
return (2) a desire to sell Solar equipment (3) a desire to further expand their operating experience base
on landfill gas (4) ample gas supply projected based on the tonnage of waste in place, and expected at
closure, and (5) the project's contract to sell power at a favorable rate to the local utility under California's
Standard Offer number 4. The convenience of the site's location to Solar's manufacturing facility in San
Diego also appears to have played a part in the decision.
Solar was able to negotiate mutually agreeable terms with the owner of the landfill, San Diego County.
The County was willing to have the energy system installed under terms where Solar operated the energy
system, was responsible for maintenance of the gas collection system, and the operator and the County
were provided a royalty from electrical sales of approximately 8 percent of net.
5.4.3 Landfill and landfill gas system
Details of the landfill and landfill gas system are given in table 21. The initial landfill gas system was
designed and installed by GSF Energy. Current vertical well pipe is carbon steel, rather than the usual
plastic; steel well pipe was selected based on its ability to better withstand compressive and shear forces
from waste subsidence in this deep landfill. Wells are equipped with zinc anodes for corrosion protection.
Collection well laterals are both below and aboveground, and the main header is aboveground. Solar
states the length of the collection well lateral piping is about equally divided between above and below
ground piping.
The 9 million tons of waste in place are expected to generate methane at a rate exceeding the gas needs
for the two turbines operating at full power (which would together be expected to consume about
450,000 scf of methane per day). Despite cover soil that is reportedly relatively porous, standard well
adjustment procedures produce an acceptable gas supply for the facility. The system has experienced
TABLE 20. GENERAL INFORMATION: SYCAMORE CANYON LANDFILL GAS ENERGY FACILITY
Location: 15 miles northeast of the City of San Diego, in San Diego County, California
General description of energy application: Electric power generation, sale to utility grid
Generating plant: Based on two Solar Saturn recuperated gas turbines, nameplate rated at 933 kW each,
with other standard Solar components
Startup date: Early 1989
Owner and operator of energy equipment: Solar Turbines
Landfill owner and overall operator San Diego County
Current and projected tonnage in place: 9 million tons In 1991,30 million tons at closure in 1998
Landfill gas collection system: Vertical well, operated by Landfill Energy Partners
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TABLE 21. SYCAMORE CANYON LANDFILL AND GAS SYSTEM CHARACTERISTICS
Landfill
Location of landfill: Mission Gorge Road, San Diego County
Type of landfill: Municipal waste, largely canyon fill
Date opened: 1962
Tonnage in place (earty 1991): Approximately 9 million
Scheduled tonnage at closure: 30 million in 1998
Climate: Semi-arid, rainfall about 10 inches per year
Cover soil material: "porous," permeability not stated
Acres/Acres filled: 530/390
Gas System Characteristics
Designed and installed by: GSF Energy
Operated and monitored by: Landfill Energy
Number of vertical wells: 50
Depth of wells: Approximately 80 feet (variable)
Depth of permeable zones in wells: Bottom third to two thirds
Current gas collection rate: 12. million cubic feet of landfill gas per day
Gas analysis: Three times weekly by gas chromatograph for methane
Procedure for well adjustment: Wells below 50 percent methane, throttled; flow rate of
those above 50 percent, increased as appropriate.
few problems from "overdrawing" (air infiltration through the surface associated with a high rate of
extraction), although it has had some problems associated with piping leaks. Leaks can result in
problems caused by gas being diluted with air. To forestall such problems, an oxygen sensor at the plant
triggers an alarm when the oxygen concentration exceeds 1.8 percent, and a system shutdown when
oxygen concentration exceeds 3.6 percent
5.4.4 Plant equipment: Gas preprocessing and energy
A simplified schematic of the energy equipment is shown in figure 9. Gas preprocessing equipment and
energy equipment characteristics are shown in table 22.
Landfill gas handling and preprocessing. The features of the gas collection system were noted above.
The equipment for further landfill gas handling and preprocessing within the plant was engineered by
Solar. Gas enters the plant through the gas system main header. A vacuum of 2 inches mercury, or
about 25 to 30 inches water column, is typically maintained at the point where the main header enters the
plant. Vacuum for gas extraction from the landfill, and motive power for initial pumping of landfill gas
within the plant, is provided by an oil-flooded screw compressor within the plant (see flow schematic and
table 22). Immediately on entering the plant, and before the compressor, this raw gas passes through a
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TABLE 22. GAS PREPROCESSING AND ENERGY EQUIPMENT AT SYCAMORE CANYON
Landfill Gas Preprocessing Equipment
In-line liquid removal by "slug catcher: Modified tank (see text)
Landfill gas flow monitoring: Daniels orifice
Landfill gas oxygen content measurement (see text): Teledyne fuel-cell based oxygen
meter
Gas filtration for paniculate and water removal: Peco coalescing filter (4 inches w.g.
pressure drop), 10 micron cutoff, and vane-type coalescer
Landfill gas compressor Solar/Howden oil-flooded two-stage, -28 inches w.g. to 150 psi
Energy Equipment
Overall generator set description: Saturn T-1300
Turbine subcomponent of generator system: Solar Saturn, Model GSC 1200R, 1988
model year.
Generator subcomponent: Marathon, 950 kW
Other electrical power system components: Standard Solar engineered package
device to intercept free liquids ("slug catcher*)- This is essentially a baffled tank designed to intercept
quantities of condensate liquid that build up or pool at low points In the gas system and may "very
occasionally* mobilize in the gas system and move with the flowing gas as a large "slug" to the plant. Any
such liquid must be intercepted to prevent damage to plant equipment. After the slug catcher, the gas
passes consecutively through a coalescing filter and vane scrubber, where aerosols and particulates
down to 10 microns are removed. The volumetric flow rate of the gas is measured by a Daniels orifice
flow meter. The scrubbed landfill gas undergoes two stages of compression in an oil-flooded screw
compressor (see block diagram in 9); gas exits the first compressor stage at about 50 psig and the
second stage at about 150 psig. The compressed gas temperature when it leaves the second stage is
about 200'F. The gas contains entrained oil from the screw compressor, which is then removed by a
knockout vessel and coalescing filter. Gas then passes to a cooler, where water is condensed out. The
gas Is then reheated to 35 to 40'F above the dewpoint before passing through a gas pressure regulator
and then to the turbine. This final reheat is needed to produce the dry gas required for trouble-free
operation of the gas turbine fuel metering system.
Turbomachlnery. The two Saturn turbine powered gensets (table 22) are adaptations of standard Solar
designs for power generation at sites such as offshore gas platforms. Plant thermal-to-mechanical
efficiency and electric power generating efficiency are improved through recuperation of inlet air with
turbine exhaust, as is commonly practiced. The need for operator attention is kept fairly tow by using a
process monitoring and control system developed by Solar. This system acquires, conditions, and
processes data and has capabilities including process control, operational data logging, and remote data
acquisition. The remaining equipment is also standard. Other specifications and characteristics of the
turbines and generating equipment are presented in table 22.
Performance/availability Issues. Solar states the net heat rate for power generation by the facility to be
about 14,500 Btus/kWh based on gas tower heating value, which translates to about 16,000 Btus/kWh
based on the landfill methane's higher heating value. The overall plant generating efficiency with this gas
turbine is tower than would be obtained on "normal" pipeline natural gas fuel; this is mostly attributable to
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HOT TURBINE I
EXHAUST
POWER
TU GRID
GENERATOR
HEATED'
COMPRESSED
AIR TO
CDMBUSTOR
RECUPERATOR
V
A
A
TURBINE EXHAUST
TO ATMOSPHERE
AIR FROM
TURBINE
COMPRESSOR
I
AIR TD TURBINE
COMPRESSOR
in
-f*
FUEL GAS
HEAT EXCHANGER
LANDFILL GAS FROM
COLLECTION SYSYTEM
VANE TYPE
SCRUBBER
SCREW
COMPRESSOR
SKID
CONDENSATE
Y
CDNDENSATE
Figure 9
Gas Turbine / Electric Power Facility At Sycamore Canyon
Simplified Block Diagram Showing Major Components
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parasitic compression work required for landfill gas. (Pipeline gas fuel is normally available under
pressure, and requires no further compression when used as a turbine fuel; however, landfill gas at
atmospheric pressure requires additional work to compress to 200 psi, as discussed in earlier sections.)
Efficiency may be slightly further reduced because less air recuperation can be practiced; air subject to
recuperation is a lower fraction of the total feed gas entering the turbine than would be the case with
natural gas fuel. (The carbon dioxide portion of the landfill gas makes up a greater portion of the diluent
gas and, with current practice, it is not recuperated.)
These factors (predominantly gas compression) add to the parasitic toad (200 kW) and reduce the
efficiency, resulting in a net output of 1.325 kW.
As normally constrained by blade temperature limits, the turbine's maximum power output increases with
the mass of gas that the turbine can take in; this mass and thus the power output increases as the
temperature of the gas intake decreases. The entering combustion air is therefore precooled on hotter
days by passing it through an evaporative cooler. Necessary on-site makeup water for this cooler is
being provided by Culligan Water until permanent city water lines are installed.
Availability. Turbine availability may be expressed as hours of on-line availability in response to need. It
can also be compared to that for the same turbine operating on a normal 100 percent available natural
gas supply. Solar states that an availability of 90 to 93 percent with landfill gas would be expected. Such
availability with normal natural gas is stated by Solar to be 98 percent, since downtime for gas turbine
maintenance is typically tow. The additional downtime with landfill gas is attributable to landfill gas field
supply problems and modifications of that part of the plant specific to landfill gas processing.
5.4.5 Environmental
Source test of generating facilities are required under rules of the San Diego Air Pollution Control District.
Two source tests have given actual exhaust gas composition results as shown in table 23.
Permitted emission levels were not obtainable. Solar states "Emission levels were consistent with current
production gas turbines. This has not limited energy recovery.*
5.4.6 Economics
Economic factors are summarized in table 24. From limited data provided by Solar, economic return
appears to have been lower than desirable to date. It must be emphasized that these economic indices
are for a limited term, and specific to this site and situation. The continuing installation of such turbines at
landfills by others (particularly Waste Management, Incorporated) attests that such turbines can be
economically attractive.
TABLE 23. SOME EMISSION TEST RESULTS AT SYCAMORE CANYON
Test date
Feb. 2.1989 Feb. 3.1989
Percent O2 (for reference): 1751 percent 17.56 percent
NOX: 49.07 ppm 40.70 ppm
CO: 4.71 ppm 4.68 ppm
NMHC: 3.5 ppm 1.7 ppm
S02: Oppm Oppm
PJG G640101A AOW
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TABLE 24. ECONOMIC DATA: SYCAMORE CANYON GENERATING FACILITY1
1. Capital investment for energy facility: $4,000,000
2. Gross revenues from electric sales (as operated)
1989: Sales $400,000
Capacity payment $150,000
Total $550,000
1990 Sales $500,000
Capacity payment $150,000
Total $650.000
3. Standard Offer number 4 electric sales contract—80 percent fixed, 20 percent floating.
Further details not available from Solar.
4. Typical operating and maintenance (not including gas): $400,000/year
Operator 40 to 48 hours/week (cost included as component of above)
5. Total gas cost (includes royalties and other costs): $350,000/year
6. Gas royalties to County: Approximately 2.5 percent of net electrical sales
7. Landfill gas system operation and maintenance costs of approximately $15,000 per
month
1. AN figures provided by Solar
5.4.7 Operation and maintenance
Day-to-day operations of the generating plant (excluding service visits and operation of the gas collection
system) are carried out by one site operator, and Solar reports an operator labor requirement of 5 to
6 days per week. The principal maintenance Items were stated to be lubricating oil, spare parts usage
and overhauls.
5.43 Discussion
Performance differences attributable to landfill gas. Solar reports that efficiency is reduced by
13 percent from the efficiency that would be obtained with the same turbine on more conventional pipeline
gas or distillate fuels. This toss is almost entirely due to the greater parasitic toad posed by landfill gas
compression.
Other problems or malfunctions of the energy equipment, specifically attributable to landfill gas, have not
been seen. (Such problems have been seen and addressed with similar turbines at other sites and were
discussed in 3.1.5. The gas preprocessing system at Sycamore as designed by Solar appears to be
adequate to prevent these problems). One problem that can be considered landfill-gas specific is posed
in gas preprocessing by the "slugs" of liquid, which occasionally mobilize and reach the slug catcher at
the plant.
Plans. A larger "slug catcher* is planned to further reduce the possibility of damage due to liquid entering
the plant. (While this modification is judged desirable by Solar, it also must be noted that this plant has
-------
suffered no damage from this source to date.) As of the site visit, Solar stated that there were no plans
for facility expansion.
Lesson learned. Other than the need to protect the plant with a larger 'slug catcher," Solar did not
identify any lessons learned regarding the energy plant itself.
Note added: In 1992, the facility was reported by Solar as sold to Laidlaw Gas Recovery Systems,
Incorporated8.
5.5 Landfill Gas Fueled Boiler: Raleigh, North Carolina
5.5.1 Introduction and general overview
In Raleigh, North Carolina, a boiler fueled by about 900 cfm (1,300,000 cfd) of landfill gas generates
steam at a rate typically near 24,000 pounds per hour to meet the needs of a pharmaceutical plant. The
energy conversion system uses gas collected from a municipal landfill (Wilder^ Grove). It consists of a
pipeline transmission system, a boiler (Cleaver-Brooks), and the building housing it at the pharmaceutical
plant (Ajinomoto). Basic features of the facility are listed in table 25. A photograph of the boiler (more
details are presented later) is shown in figure 10. Capital investment for the pipeline, pumping station,
and boiler totals approximately $900,000. Gross revenue from steam sales is running in the range of
$450,000 to $500,000 per year.
Participants in the project include Natural Power. Inc. (Natural Power), which had major responsibility for
implementing the project; Raleigh Landfill Gas Corporation (RLGC), an affiliate of Palmer Capital, which
installed the gas collection system and provide gas to the facility; Ajinomoto USA (Ajinomoto); and the
City of Raleigh (City), which owns the landfill. The ownership and operational arrangements are also
summarized in table 25. Natural Power revenues are derived from the sale of steam to Ajinomoto.
Royalties from the steam sale revenues are paid to the City of Raleigh. Landfill gas used in making
steam is purchased by Natural Power from RLGC. The CHy also gains environmental benefits from
operating a gas system at its landfill, and RLGC benefits from tax credits on the landfill gas sold to
Natural Power. Ajinomoto is supplied steam for its pharmaceutical plant operations at a competitive cost.
System performance to date appears satisfactory for all partidpams.
5.5.2 History of project Implementation
The history of this project provides another example of complexities that can be encountered in attempts
to find appropriate landfill gas energy uses, and then to implement a system. Securing needed landfill
gas rights was difficult; much further analysis and investigation was also involved in the selection of an
energy application and user. Events that occurred along the way to Implementation of the current energy
system included the following.
Negotiation for landfill gas rights. The City initially recognized the energy and income potential of gas
from Its landfills, and offered gas rights to Its landfills by auction In 1984. Natural Power was one of six
bidders for these rights. The award of rights was based largely on the royalty offered by bidders on
landfill-gas-derived energy income, and rights were awarded to another bidder, promising the highest
royalty. About 2 years were required to establish that the bid winner (now out .of business) did not have
the necessary resources to implement an energy system; the total delay engendered by these events
was well over 2 years.
8 Ptnonal communication. R. AucsWmricz, Solar to D. Augenstoin. EMCON. February 1892.
PJG G640101A ArtW
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Figure 10 Cleaver-Brooks Boiler at Plant of Ajinomolo, USA. LandliH gas fueled boiler generates up to
24,000 pounds per hour of steam for plant process use.
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TABLE 25. STEAM BOILER FUELED BY LANDFILL GAS: BASIC FEATURES
Location: Approximately 5 miles east of Raleigh, North Carolina
Nature of application: Landfill gas is extracted, piped 3/4 mile and used to fuel a boiler. The boiler
supplies the steam needs of a pharmaceutical plant.
Project start date: December 1989
Participants: Natural Power, Inc. (Natural Power), Raleigh Landfill Gas Corporation (RLGC), Ajinomoto.
Inc. (Ajinomoto), and City of Raleigh (City)
Component Owned bv Operated bv
Landfill City City
Landfill gas system RLGC Natural Power
Pipeline Natural Power Natural Power
Boiler (Cleaver-Brooks) Natural Power Ajinomoto/Natural Power
Boiler facility Natural Power Ajinomoto/Natural Power
Natural Power continued its efforts and the City Council ultimately awarded Natural Power the gas rights
to Wildefs Grove landfill. It was known that the amount of waste in place was likely to produce sufficient
gas. Gas availability was confirmed with a 12-well test program in 1987. Natural Power had meanwhile
been examining energy options; the experience and interests of Bill Rowland of Natural Power, had
included the use of two small (85 kW) landfill-gas-fueled Caterpillar engines at the Rowland landfill in
Raleigh beginning in 1983. In the mid-1980s, Natural Power had begun to look at generating units based
on Caterpillar. Cooper-Superior, and Waukesha 1C engines and Solar Gas turbines, and investigated
these more intensively with the acquisition of gas rights. Boilers .were also investigated; they were
determined to be among the most fundamentally attractive of the options based on return on investment,
and specifically in light of revenue based on avoided costs of natural gas or oil, which landfill gas could
displace.
In 1987, Ajinomoto, under a mile from the landfill, was found to be a potential customer for boiler steam
fueled by landfill gas from Wilder* Grove. After further evaluation it was determined that the Ajinomoto
boiler option was the best of the alternatives. Palmer Capital (through RLGC) established a development
relationship with Natural Power and the arrangement that currently exists was implemented.
Natural Power notes that the present arrangement only came about after many years of work on the
project during which there was no financial return. The project came to fruition only because of the
continued interest, knowledge, and persistence of the participants.
5.5.3 Landfill and landfill gas system
Details of the landfill and landfill gas system are shown in table 26. Wilder* Grove is a large "cut and fill"
landfill that has been in operation since 1972. The landfill receives 1,200 to 1,400 tons per day of waste,
5 days per week, and is expected to contain approximately 6 million tons of waste at closure. The landfill
gas system was adapted by Natural Power from an initial design by SCS Engineers and, as of early 1991,
had 70 wells. Other characteristics are as noted in the table.
By indicators including waste in place, the 1987 12-well test, and operational experience, the Wilder*
Grove landfill generates methane at a rate probably greatly exceeding conversion needs. A good clay
cover undoubtedly helps maximize methane recoverability and prevent air entrainment. Satisfactory gas
P.?G
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TABLE 26. LANDFILL AND GAS SYSTEM CHARACTERISTICS: WILDER'S GROVE
Landfill
Location: Raleigh, North Carolina
Type: Cut and Fill
Date Opened: 1972
Waste in Place (1991): 3.3 million tons
Waste Rll Rate: 325,000 tons/year
Total Fill Area: 125 acres
Area Now Filled: 65 acres
Climate: Temperate, warm, wet
Annual Rainfall: 50 inches
Daily, Intermediate, and Rnal Cover Soils: Clay
Gas Extraction System
Type: Vertical Well
Pipe Material: HDPE
Lateral/Main Header Piping: Below ground
System Details: Waste depth 40 to 100 feet. Well depth typically 80 percent of waste depth.
Laterals and headers typically 3 feet below surface.
Current Landfill Gas Collection Rate: 900 cfm (1.3 million cfd)
Well Adjustment Protocol: GasTechtt meters used to analyze for methane. Wells with flow
below 50 percent throttled: flow of wells above 50 percent maintained and metered as needed.
Gas Composition: Near 51 percent methane
Gas Analysis Frequency: 12 times each month
quality of about 51 percent methane is obtained with a three-times per week monitoring and adjustment
schedule. (Some problems have occurred with leaks and their detection in below-grade lines but these
have not been serious enough to impede energy operations.)
5.5.4 Energy equipment: Blower station, pipeline and boiler
Equipment characteristics are summarized in table 27.
Blower/pumping station. Motive power for gas extraction and.gas pumping through the pipeline is
provided by a blower as shown in table 27, which receives gas at up to 40 inches of water vacuum and
discharges it at approximately 12 psig. A filter system, with particle size cutoff of 1 micron, removes
particles and aerosols from the gas. The pumping station with blower and filter was engineered by
Perennial Energy, Inc., of West Plains, Missouri.
Pipeline. The pipeline extending from the pumping station at the Wilder* Grove Landfill to the boiler at
the Ajinomoto factory is a 12-inch outer diameter HDPE pipe. The pipeline slopes from each end toward
«niv
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TABLE 27. SUMMARY OF ENERGY EQUIPMENT CHARACTERISTICS
Blower station
Blower Hoffman 9 stage with GE motor
Filter: Dual paniculate (custom design, Perennial Energy)
Pipeline
12-inch outer diameter HOPE, length 3/4 mile
Energy Equipment
Boiler. Cleaver-Brooks CB 800 hp; normal rating 26,800 Ib/hr steam on natural gas or oil
Building housing boiler: Standard rectangular, 25-foot by 52-foot; dimensions adequate to allow
access, tube removal, and other maintenance work
the center so that all condensate can be collected at a single low point, located at a city sewer line near
the midpoint of the pipe. The pipeline is sized for greater than the current gas flow to allow for possible
increased landfill gas consumption by the end user (Ajinomoto, see later).
Boiler and building. The Cleaver-Brooks boiler is nominally rated at 26,800 pounds per hour of steam
on natural gas. Landfill gas is fed to the boiler at 8 to 9 psi. Other characteristics of the boiler are listed in
table 27 and presented in appendix J. This is a standard industrial boiler; its load varies as plant steam
demand (for steam sterilization and other purposes) varies over the day. It is housed in a building
specifically designed for it (as noted in the table), furnished by Natural Power.
One important boiler feature is its ability to operate on several different fuels: pipeline natural gas.
number six fuel oil, and landfill gas., This provides insurance against steam supply interruptions because
of a lack of landfill gas fuel. The principal modification to the boiler to adapt it to landfill gas use was
(according to Ajinomoto factory staff) an increase in the number of gas injection ports (to accommodate
the greater flow of landfill gas that must be introduced into the burner) and "minor modifications to the air
supply. Some fine-tuning was required after boiler installation.
5.5.5 Performance
Boiler. Over-all boiler availability and performance, has been very good. The Cleaver-Brooks boiler
normally supplies about 75 percent of the pharmaceutical plant's steam needs as the "primary* and
lowest cost steam source; other backup boilers at Ajinomoto can fill in when it is not available. Natural
Power reports that the boiler's availability to meet its share of plant steam needs when its steam
production could be used has been near 97 percent since installation. Much of the initial down time has
been shutdown for normal preventive maintenance and adjustments; a boiler gasket also had to be
replaced. No operating problems that would be attributable to operation on landfill gas, such as unusual
corrosion, have been observed.
The thermal efficiency of the boiler, as measured by Cleaver-Brooks at the Ajinomoto plant, has been
81.5 percent. This is close to the efficiency expected with pipeline gas and above the 80 percent
efficiency Cleaver-Brooks guarantees with pipeline gas. At full output the steam generation rate has been
near 24,000 pounds per hour, compared to an expected rate with pipeline gas of 27,600 Ib/hr. This
decrement In steam output of about 10 percent is expected as a normal consequence of the C02 dilution
effects with landfill gas. The controls, which balance the air and gas feeds based on exhaust oxygen
levels to tune the boiler, function well.
P.in RftdnmiA Anw
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Other. The pipeline blower station, and blower and filter provided with it, have been performing well with
no unexpected problems. Natural Power reports that no modifications have been necessary.
5.5.6 Emissions
Ajinomoto notes that the emissions have been standard for a boiler of this type, and satisfactory based on
regulations.
5.5.7 Operation and maintenance
To date Ajinomoto reports that operating and maintenance needs for the boiler are 'as normally
experienced" for boilers of this size and type. The impact of minor maintenance work on boiler service
was mentioned above. Automated controls allow the boiler to be operated with very little attention. The
boiler incurs charges for electricity, inspections, fees, and insurance, which are discussed under
"Economics" (section 5.5.8).
The filter in the automated condensate drain of the landfill gas pipeline requires cleaning, a minor job that
is reported to take about 2 hours once a year. The filter in the pumping station has to be replaced when
pressure drop increases significantly (from 2 inches w.g. to, say, 3 inches).
Note that much of the system has not operated long enough for indicative operation and maintenance
histories to be developed.
TABLE 28. ECONOMIC DATA FOR LANDFILL-GAS-FUELED BOILER: RALEIGH, NORTH CAROLINA
Approximate system capital costs:
Item Cost
Landfill gas system
Blower station
Pipeline
Boiler and Building
$500,000
$100.000
$200,000
$600,000
Owner
RLGC
RLGC
Natural Power
Natural Power
Financed bv
RLGC
RLGC
Natural
Natural
Power/First Citizens Bank
Power/First Citizens Bank
Price paid for steam: Typically near $3.00/1,000 bs.
Gross steam revenue, December 1989 (installation) to February 1991: $458,371
Current gross steam revenue, annualized: $450,000 to 500,000
Gross steam revenue distribution: Net proceeds to Natural Power, after royalties and gas purchase, are
approximately 40 to 45 percent of gross revenue, approximately 40 percent of gross revenue goes to
RLGC and approximately 15 percent to the City
Tax credits (to RLGC): Approximately $0.85/mmBtu sold in 1990 (this will fluctuate based on inflation
factor)
Natural Power payments relating to boiler: Electricity, $12,500 per year; insurance, $26,400 per yean
inspections/fees, $3,000 per year
Payments by RLGC to Natural Power for gas system operation and maintenance: Approximately
$42,000 per year
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5.5.8 Economics
Economic data are shown in table 28. The source of revenue is steam sales to Ajinomoto; the steam
price is tied to the lowest cost fuel that is a reasonable alternative to landfill gas, usually natural gas from
the local utility. This results in a steam revenue, as stated by Natural Power near $3 per 1000 IDS. Gross
revenue figures from inception to February 1991 are as shown in table 28. Natural Power states that,
based on current experience, annual revenue will continue to be $450,000 to $500,000. Gross steam
revenue, paid to Natural Power, is used to pay royalties to the City of Raleigh and to purchase landfill gas
from RLGC.
RLGC, owner of the landfill gas system and provider of the gas, also receives tax credits. The specifics
were not available but are at a rate based on the Wilder's Grove gas recovery rate and should exceed
$150,000 per year.
Other payment arrangements are as shown in the table, by Natural Power for boiler maintenance, and by
RLGC to Natural Power for operation of the gas field.
Translating these figures into a return to the participants would need more detailed information in various
areas such as financing arrangements and depreciation schedules and is not attempted here. All
participants do appear to be satisfied with the economics.
5.5.9 Discussion
Performance effects attributable to landfill gas. The significant difference in energy equipment
performance due to using landfill gas is the reduced boiler steam output, (approximately 10 percent).
This is an expected consequence of the CO* dilution of the methane when landfill gas is used. In all
other respects, performance appears to be comparable to that expected with more conventional fuels.
Other Issues. The performance of other equipment has been as expected, and the parties contacted
(Natural Power and Ajinomoto) appear to be pleased. Economic performance has been satisfactory.
Lessons learned. The principal lesson learned to date appears to be that the system can function as
planned and, more generally, that boiler fueling with landfill gas can be an attractive application.
Plans. In view of the availability of gas, additional pipeline capacity, and performance of the system to
date, Ajinomoto and Natural Power are considering various additional gas uses including absorption
chillers and steam turbines.
5.6 Electrical Power Generation Using Caterpillar Engines at the Central Landfill,
Yolo County, California
5.6.1 Introduction and general overview
The Yolo County Central Landfill is about five miles northeast of the town of Davis, California. Gas from
the landfill fuels an energy conversion system consisting of three Caterpillar engine powered gensets,
whose collective output totals near 1,500 kW. The generated power is delivered via an interconnect 3/4
mile to nearby PG&E high voltage power lines. A photograph of the facility is shown in figure 11.
General site and equipment information is shown in table 29. The various participants and their
responsibilities in the project are:
• Yolo Gas Recovery Corporation, a partnership between Palmer Capital and Hazox,
has until recently owned and had overall managerial responsibilities for the energy
equipment, that is, the gensets, gas cleanup train, interconnect and other associated
equipment.
PJG GB40101A AOW e->
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Figure 11 Electrical Generating Facility at Yolo County Central Landfill. Trailers each house engine-
generatonj driven by Caterpillar G399 engines. Gas pretreatment equipment Is to ten of picture.
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• Stowe Engineering has most recently been managing the day-to-day operation of the
energy equipment.
• Operation, maintenance, and management of the landfill gas system and delivery of
collected gas to the gensets has been the continuing responsibility of Monterey Landfill
Gas Corporation, a subsidiary of EMCON Associates.
• Yoto County, the owner of the landfill, receives royalties based on net power revenue
but has no managerial involvement.
YGRC has until recently received its benefits in the form of a portion of the gross electrical power
revenue. Stowe and other equipment operators (see below) have received contract payments for
operating the equipment, which are in part tied to performance. MLGC receives benefits in terms of tax
credits, and a royalty on net electric sales.
This project has been marked by several difficulties, posed both by site conditions and equipment
problems. Although some of the problems have been resolved, the problems and consequent falling
revenue have been severe recently. These are discussed below. It must be recognized that records are
in some cases incomplete because of recent changes and events that have occurred.
5.6.2 History of project Implementation
The County initially commissioned a landfill gas recovery study in 1983, conducted by EMCON. Test well
extractions were run in 1983 (and subsequently). The recoverable gas was also forecast at several times
using various assumptions and an EMCON model. One set of the model projections for this landfill have
been published (Augenstein and Pacey, 1991); the well tests indicated somewhat higher availability than
did the model projections. Based on a combination of model and test well results, as well as assumptions
about future waste placement rates, gas availability was judged sufficient to support the three gensets
actually installed (if not immediately on installation, then within a reasonably short time thereafter as gas
recovery would continue to rise over time).
In 1987, the county commissioned additional work with EMCON to develop a bid package to enable the
selection of a developer for a gas recovery project. Several factors were helpful to implementation of this
project: a favorable electrical energy pricing schedule, a significant and growing waste repository, and an
enthusiastic and progressive County administration. This project was difficult to implement as the
competition for the project involved a number of bidders and an extended bid process. Near the end of
the bidding process, the local utility terminated the offering of its most favorable energy pricing contract (A
California Standard Offer Number Four), which was one key to project viability. Palmer Capital had
secured such a favorable standard offer contract from the utility just before the deadline, but no other
bidder did so. Subsequent to Palmer's securing the standard offer, the County awarded Hazox the
contract to develop the project. Hazox was unable to secure a contract as favorable as Palmer's from
PG&E; however Hazox and Palmer recognized that each held a necessary ingredient for a successful
project. They were able to jointly able to agree on a partnership approach which led to the formation of
YGRC. •
YGRC, which had responsibility for the energy equipment (excluding landfill gas recovery) invited
EMCON to acquire the landfill gas rights and to undertake the collection system installation, operations
and management. EMCON placed this project into Its gas recovery subsidiary, MLGC.
Gensets driven by three Caterpillar G399 engines were secured by YGRC from Tenco Corporation, of
Sacramento, California. This acquisition was possible at a favorable price, because this line of engines
was being discontinued by Caterpillar and two of these engines were surplus to other needs that had
been anticipated earlier; the third engine was reconditioned. This engine model has been used
extensively as a naturally aspirated landfill gas engine (see GRCDA/SWANA, 1989). However, Yoto
represented its first use in a lean-bum operating mode.
o irs rs
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TABLE 29. BASIC FEATURES: ELECTRICITY GENERATION AT THE YOLO COUNTY CENTRAL
LANDFILL
General Nature of Application: Electric power generation and sale to grid
Location: Five miles northeast of Davis, CA. (also, 12 miles northwest of Sacramento, CA)
Energy equipment: Gensets powered by three Caterpillar G399 Engines, with auxiliaries including gas
processing skid and interconnect
Energy equipment owner Yolo Gas Recovery Corporation (YGRC)
Gas extraction system design: EMCON Associates
Gas system operation: Monterey Landfill Gas Corporation (MLGC)
Landfill owner: Yolo County
Landfill operating contractor: Earthco
A compression/refrigeration approach to gas cleanup was selected, based on availability of a low-cost
reconditioned unit that was obtained from Southern California where is had been previously used for
landfill gas treatment. The possible significance of this choice to project problems is also discussed later.
Design and construction of the facility was carried out by Wellhead Electric Corporation of Sacramento,
California. The first electricity production was in October 1989.
Of note as part of this implementation process is that a number of operators have been employed since
startup. Wellhead Electric was the initial operator of the system from October 1989 to July 1990. EOS,
Inc., was operator from July 1990 to February 1991. From February 1991 to May 1991, the system
operation was supported by the efforts of Richard Ontiveros of Palmer Capital. From May 1991 to
November 1991. Perennial Energy headquartered in West Plains, Missouri, was the operator subsequent
to withdrawal of YGRC and Perennial from the project (in November 1991) Stowe Engineering of Quincy,
MA has been responsible for operations, as well as certain other managerial duties related to energy
equipment.
5.6.3 Landfill and landfill gas extraction system
Details of the landfill and landfill gas extraction system are presented in table 30. The Central Landfill is a
large landfill of the "area fir type, begun in 1976. Fill rate is about 1,000 tons per day of mostly municipal
waste: slightly over 3 million tons had been placed as of early 1991. Depth of fill ranges from 30 to
70 feet in the areas where gas is currently extracted.
The landfill is managed to maximize landfill gas recovery while maintaining a relatively high level of
methane concentration (generally 49 to 51 percent). Modules are of variable size and depth; each
module is monitored at least twice weekly and appropriate weP and header adjustments in flow are made
to achieve the desired control. There is relatively small fluctuation in gas quality and quantity on a short-
term basis. Occasional problems occur in the gas collection system delivery, generally attributable to
pipe joint failure, or flexible coupling failure. These conditions are usually repaired within a few hours of
their occurrence. All piping is PVC and, with exception of the vertical wells, is above ground.
Landfill gas quantity should increase gradually as the waste resource expands over the coming decades.
-------
ENGINE
EXHAUST
TO
ATMOSPHERE
INTERCONNECT
TO GRID
GENERATORS
LANDFILL GAS FROM
COLLECTION SYSTEM
CATERPILLAR
ENGINE(S)
(3)
2-STAGE
COMPRESSOR
1 PSI TO 60 PSI
AFTERCODLER
CONDENSATE
TURBOCHARGER
COALESCING
FILTER
AIR
— -^
*-~^
PROPANE
CHILLER
(TO 35 F)
•— . .»,
~— =*
MOISTURE
KNOCKOUT
\
/
CONDENSATE
Figure 12
Electric Power Generation Based Dn Caterpillar Engines
At Yolo County Central Landfill
Simplified Block Diagram Showing Major Components
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TABLE 30. LANDFILL AND LANDFILL GAS SYSTEM: YOLO COUNTY CENTRAL LANDFILL
Landfill
Landfill type: Area fill
Location: Yoto County, 5 miles northeast of Davis. CA (12 miles northwest of
Sacramento, California)
Waste type: Residential municipal
Waste depth: To more than 70 feet
Rl rate: 280,000 tons/year (in 1991)
Climate: Semi-arid (rainfall: 15 inches per year)
Final cover: 4 feet of clay
Gas extraction System
Type: vertical well
Number of active vertical wells: 80
Laterals and main header: PVC, above ground
Permeable zone of wells: Extending from 20 feet below landfill cover to bottom of well.
Current collection rate: 900 to 950 dm
Well adjustment objective: To maximize Btu delivery to gertsets, while maintaining gas
concentrations over 52 percent
Adjustment protocol: Flow of wells showing over 52 percent methane increased until
concentration begins to fall; wells under 52 percent throttled. Wellhead composition
monitored and well flows adjusted approximately once per month.
Gas analysis method: Wells and main header by GasTech® thermal conductivity based methane
meters.
5.6.4 Gas preprocessing and energy conversion equipment
A simplified block diagram for the energy conversion system is shown in figure 12. A listing of the gas
pre-processing and energy conversion equipment is presented in table 31.
Landfill gas handling and pre-processing. A variable-speed Hauck centrifugal blower normally
provides the vacuum used to extract the gas from the landfill. The gas is delivered to a 2-stage
compressor. The first stage compresses the gas to 15 psig, and the second stage further compresses
the gas to a discharge pressure of 60 psig. (The blower may also be bypassed, and the field vacuum
provided by the compressor.) Pre-treatment occurs initially by passage of the gas through 2 knockout
pots before the gas enters the compressor. The gas entrains some oil and is heated to about 275'F in
the compression cycle. The gas is then cooled to 78T as It passes through oil knockout and an
aftercooler. It then passes through a refrigeration unit to tower the temperature to 35'F; resulting
condensate is bled at several takeoff points from the aftercooler and in refrigeration steps. The gas is
reheated to 80 to 90°F as it leaves the refrigeration unit and passes through a coalescing filter just prior to
being delivered into the internal combustion engines.
anw
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Electrical genset equipment. The internal combustion engines are Caterpillar units, Model Cat G-399,
each rated nominally at 650 kW on pipeline natural gas. These are an earlier line of Caterpillar natural-
gas-adapted engines. They are stated to be without certain landfill gas adaptations incorporated by
Caterpillar0 engines of more recent manufacture. Cooling water at the site has been provided by on-sfte
wells; other options are under consideration because of water quality. An evaporative cooling tower is
provided in association with each engine to cool air for carburetion.
The YGRC facility includes an interconnect that steps up voltage from that of the generator to power lines
3/4 mile away. The contract for power sale by the facility would permit the sale of up to 12 MW of power
to the grid. Since the facility can typically generate near 1.5MW, more than 10 MW of additional
generating capacity could be accepted.
5.6.5 Performance and availability Issues
Net engine output. The gross capacity of the gensets—if operated on natural gas—would be around
1.950KW. The net power output has been experienced, however, at between 1,300 and 1,500 kW
depending on operating factors. Factors leading to the lower power output include a normally expected
decrement of about 200 kW due to the use of landfill gas, as opposed to pipeline or natural gas. An
additional loss is due to about 200 kW of parasttics (including about 80 kW of power used by the
refrigeration equipment on the skid). These two factors would atone reduce output from 1,950 to about
1,550 kW. Other problems including engine landfill gas compressor inefficiency (due to corrosion and
suspected piston btowby), reduce output still further. An additional consideration is that less gas has
been extractable in summer, when the landfill clay cover dries and is more permeable, than in winter.
Gas does not limit output during the winter (the California rains seal the cover) but does slightly in
summer, the result of all of these factors is that output is in the 1,300 to 1,500 kW range. (The
expectations of YGRC were, apparently, that 1,700 kW of net output would instead be obtained at
optimum operating conditions)
TABLE 31. GAS PRE-PROCESSING AND ENERGY CONVERSION EQUIPMENT AT THE YOLO
COUNTY CENTRAL LANDFILL
Gas Handling and Processing
Blower: Hauck 25 HP. (at maximum power) model TBG-9-071-271-FX-1
Compressor: Joy Manufacturing, appx. 1 psig to 60 psig. (model WBF72XHD)
Chiller: York, propane working fluid, cools gas from ambient to 34-36T (model not
available)
Moisture knockouts and demisters: Custom fabricated
Final gas filtration, just prior to engine: Coalescing, model not available
Energy Equipment
Gensets: Three Caterpillar G-399 16 cylinder engines, driving generators. 650 kW
(gross nameplate capacity on pipeline natural gas)
Cooler for engine intake air: Custom design, evaporative
On-site water supply: Wells
Personal communication, Curt* Chadwick. Caterpillar Corporation, Mossvite, IKnois. September 1091.
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Regarding efficiency, YGRC reports that the heat rate of the engine, when operating optimally, has been
near 12,500 Btu/kWh (which is good). Note, however, that this value is somewhat uncertain given some
gas flow measurement uncertainties.
As an introduction to further discussion of performance and availability issues, note that these have been
poor because of both equipment and site-specific problems. These have included, but are not limited to,
the following:
• Engines damaged by liquid landfill gas condensate entering the engine intake manifold
with the landfill gas. (This is shown in site operating logs.) This has apparently
occurred despite the existence of knockout pots and other equipment that were
designed to prevent such occurrences.
• Corrosion of all engines, typical of engine attack by acidic combustion products as
outlined in section 2. The most serious problem began with valve and valve guide
erosion, which occurred to such an extent that valve play resulted in valves hitting and
scoring cylinder liners, damaging them.
• Problems relating to well water hardness. As noted, the well water, which has been
used for cooling is extremely hard (hardness reportedly increased sharply in 1989 after
the major October earthquake, which may have cracked the well casing). This has led
to deposit buildups in the engine block and oil cooler ports, through which the water
circulates. Such ports had to be manually cleaned frequently, or else engines and oil
overheated. Solids buildup and btowdown also posed a problem with evaporative
coolers.
• Limitations posed by landfill gas supply. For reasons identified earlier, landfill gas
supplies have been adequate during wet seasons when the moist clay final cover
sealed well, but may have been slightly limiting (reducing power by up to 10 percent
relative to that otherwise attainable) when the cover dried in the summer.
In addition to an of the above, less serious mishaps have occurred, such as Hauck blower breakdowns
causing limited shutdowns, refrigeration equipment breakdowns, and electrical panel shutdowns because
of overheating. There was also an extremely hard freeze in December 1990 that damaged water lines
(by freezing and bursting), evaporative coolers, and other equipment.
Engine corrosion/wear problems might be considered among the most serious problems at the site.
These are exemplified by recent experiences with the three genset engines, after an earlier overhaul that
left cylinders in good condition. The findings were by borescope (a process allowing the interior of the
cylinder to be inspected visually for damage). Engine 1 had run about 1,200 hours, engine 2 about 2,400
and engine 3 slightly over 3,000 hours. Borescope inspection showed that the cylinder liners of engines 2
and 3 were severely damaged. The damage apparently resulted from a sequence in which wearing valve
guides allowed valve stems to wobble, the wobbling valves wore the seats, and this wear also allowed the
valves to hit, score, and seriously damage the cylinder liners. The damage to engines 2 and 3 was
serious enough that they were shut down. Engines 1 and 2 were renovated and put back into operations
as of December 1991.
The problems above have resulted in service factors (output in relation to a selected standard of fuD
continuous power production) which are low. Net kilowatt hour sales for 1989,1990, and 1991 are shown
in table 32. If service factor is defined as output in relation to continuous output at a power operation of
1,400 kW, the service factors for 1989 would be less than 50 percent, and for 1990 68 percent. YGRC*s
preliminary projection for 1991 (see further discussion below) was for power production which translates
to a service factor of 47 percent
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5.6.6 Environmental/emissions
YGRC states only that the facility has been in compliance with all permit requirements, and that no
problems have been experienced.
5.6.7 Operation and maintenance
The normal day-to-day operations at the site are carried out by a single operator. Additional maintenance
is earned out such that YGRC has reported a total labor requirement at the site of about 60 hours/week.10
Engine oil was initially Hydrotech, changed at approximately 1,000-hour intervals, but was recently
switched to Mobil Pegasus 446. Intervals between changes are currently around 850 hours. YGRC,
while not reporting exact intervals between engine rebuild, maintenance steps, and so on, reports (as
could be expected) that these have been far more frequent than desirable10. The range of other
operating difficulties described in 5.6.5 has been very much outside of routine; such information as was
available on those problems was presented in that section.
5.6.8 Economics
Table 32 shows that economic information available when this report was prepared. A portion of the
energy equipment capital investment was provided by a loan from the State Street Bank and Trust
Corporation of Boston, Massachusetts. Gas rights were purchased by EMCON associates for
$1.4 million dollars, and EMCON also furnished the gas system construction for an additional $300,000
as shown. The power purchase contract is a variation of California's Standard Offer Number 4. The
contract allows PG&E to curtail (not pay) the vendor, YGRC, for up to 1000 hours per year. The gross
revenues for 1989 and 1990, as well as YGRC's estimates for 1991 revenue are shown. It should be
emphasized that 1991 revenues are only estimates; exact 1991 revenue and its allocation to participants
is not currently available.
The economic situation has been quite evidently bleak. To summarize, the combination of lower than
expected revenues, combined with high repair costs, caused default on the loan from State Street Bank in
November 1991. Perennial Energy withdrew from the project in November. Stowe Engineering of Quincy,
Massachusetts has taken over management of the energy equipment operations from YGRC and
Perennial; MLGC (EMCON's) role remains unchanged and it is continuing to operate the gas system.
Despite these serious problems, these are positive factors from economic and other standpoints. The
site has a good power contract, interconnect, and other features. With successful operation of the
gensets at service factors comparable to Brown Station Road, Otay, or Marina as discussed in this report,
Yoto is judged to have the potential tor an acceptable return.
5.6.9 Discussion
The energy facility at the Yoto County Central Landfill has experienced problems that have been serious
by normal standards of landfill gas energy projects, which often experience problems. The causes of the
problems remain to some extent speculative, but it is worth offering speculation both as to cause and the
potential remedies.
The corrosion problems seen with the gensets seem attributable to the combination of (1) reliance on a
compression/refrigeration system tor gas cleanup, with (2) engines whose conventional construction of
earlier design may have imparted little resistance to acid gas corrosion. As noted in section 2.
refrigeration will not be particularly effective in removing tower molecular weight halocarbons,
10
Personal communication. David Marquaz. Palmar Capital Corporation. San Frandsoo. CA. September. 1M1.
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TABLE 32. ECONOMIC DATA: ENERGY FACILITY AT YOLO COUNTY CENTRAL LANDFILL
Capital investment for energy equipment: $1.8 million
Payment for gas rights, by EMCON: $1.4 million
Cost of gas extraction system (paid by EMCON): $300.000
Kilowatt sales and power revenue by yean
year kWn output PG&E power payments
1989 900,720 $70,844
1990 8,366,190 $877,518
1991 (est). 5,800,000 $700,000
Tax credits realized by EMCON: 1989 « $215.900,1990 • $198,920
Power Contract: Variant of California Standard Offer 4.
Terms of Perennial Energy Contract: Payments based on kWh output-further detail not available
Distribution of power revenue to participants: Not currently available
Operating costs: Not currently available
particularly the CFCs. Hatocarbons have evidently entered the engines and acid gas combustion
products have been produced. Information is not available on how, specifically, the existing Caterpillar
G399 engines that are not landfill-gas adapted differ from later models that are. It is, however, clear that
corrosion susceptbilHy has been a major cause of problems at the site. (Also note that the G399 engine
in stoichiometric-bum mode has served extensively in earlier landfill gas applications. See Chadwick,
1989).
The problem of condensate entering the engine appears, in retrospect, to be due to an unanticipated
sequence of events that occur when one or more engines are idle. Line layout and design were such that
with one or two engines operating, condensate would pool in the gas lines entering the idle engine(s) and
on restart would be entrained into the engine being re-started in spite of traps.
Other problems at the site have already been discussed in some detail in 5.6.5.
Potential mitigating steps. It is not clear that the landfill gas refrigeration skid provides engine
protection commensurate to its cost or energy consumption (80 kW). It is possible that effectiveness in
removing the halocarbon components is minimal. Stowe Engineering, now in charge of the energy
equipment (on behalf of State Street Bank) is considering eliminating ft entirely. Stowe is also considering
the replacement of certain key engine parts, currently corrosion susceptible, such as valve guides, with
parts made of more corrosion resistant materials. This is in planning stages. Other problems have
straightforward solutions: condensate entry into the engines can be eliminated through proper redesign.
A soft water supply can be obtained by several possible routes now under consideration such as reverse
osmosis. Gas supply problems to the extent seen could be readily eliminated by pipeline gas
supplementation. Analysis and planning for a combination of such mitigating steps are underway.
5.7 Other Relevant Case Studies and Information
The preceding case studies presented recent information on six representative landfill gas energy
applications in the U.S. Many additional descriptions and studies of past and current landfill gas energy
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applications, with varying amounts of detail, can also be found in the literature. Some further information
sources are as follows.
Methane Recovery from Landfill Yearbook. The Government Advisory Associates, Inc. (GAA) has
published (in 1986,1988, and 1991) the Methane Recovery from Landfill Yearbook. GAA circulates a
questionnaire to all U.S. landfills identifiable as delivering their gas to energy applications. The yearbook
publishes data based on all responses obtained, which includes summary information on landfill features,
gas recovery, type and capacity of energy application, owners/operators, contacts, and other information.
Statistical analyses of collected data are also performed to develop overviews of issues such as
economics (some of the statistics have been cited in this report). Although data in some areas are not as
complete as the case study data in this report the yearbook contains a wealth of information and is by far
the most complete available reference in terms of numbers of sites covered in the U.S.; it is available
from GAA, 177 East 87th Street, New York, New York 10128.
SWANA/GRCDA Landfill Gas Conference Proceedings. Descriptions of landfill gas energy applications
are found in past proceedings of landfill gas symposia sponsored by SWANA (Solid Waste Association of
North America; formerly the GRCDA), as follows:
Tour Sites. In many instances the SWANA annual landfill gas conferences were held near the sites of
landfill gas energy applications. These were generally available to be toured by conference attendees,
and fact sheets including site description, application, and other data are published in the conference
proceedings. A list of the descriptions of specific tour sites is presented, arranged by year and
proceedings issue, in table 33. (Note that, as published in the conference proceedings, the data on many
tour sites may be rather limited.)
Some of the more detailed case histories In past SWANA proceedings (in many cases listed under
GRCOA), providing information somewhat similar to the case studies of this report, include the following:
• A discussion in the 1989 proceedings by major engine manufacturers (Caterpillar,
Cooper Superior, Waukesha, Solar Gas Turbines) of experience on landfill gas
(articles beginning on page 187). Discussions of corrosion effects are included.
• A discussion in the 1986 proceedings (page 158) on the selection of the energy
conversion process and project implementation, for a landfill gas fueled boiler project
for a Goodyear plant in Lansing, Michigan (Guter and Nuerenberg, 1986).
• A discussion in the 1986 proceedings of several electrical energy projects (Jansen,
1986, page 135, and Cortopassi, Toth, and Williams, 1986, page 185).
• A case study in the 1984 proceedings on the collection and use of landfill gas at a
wastewater treatment plant (McDonald, 1984, page 109).
• A discussion in the 1984 proceedings on three small electric projects (Nielsen, 1984,
page 135).
• A discussion in the 1984 proceedings on the planning of a medium Btu plant in
Cinnaminson, New Jersey (Yeung, 1984, page 238).
SWANA, from whom past proceedings are available, is located at 8750 Georgia Avenue, Suite E-140,
Silver Spring, Maryland, 20910.
U.K. Program. After the United States effort, the United Kingdom's (U.K.) effort is perhaps the largest.
The documentation of energy uses in the U.K. has been extensive; a wealth of information has been
compiled with active government support. Some brief fact sheets on two electrical generating projects
and two boiler projects are included for reference in appendix K.. Lengthier case studies of interest
include the following:
• A description of the electrical generating project at Stewartby, U. K., (ETSU, 1989)
amplifying the summary description of this site in appendix K.
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TABLE 33. SWANA LANDFILL GAS ENERGY FACILITY TOUR SITES
SWANA/GRCDA
Proceedings Year
1991
Tour site
Described
Otay2, San Diego, CA
Sycamore Canyon2, San Diego, CA
1989 Crazy Horse, Salinas, CA
Santa Cruz, CA
Marina2, CA
1986 Mountaingate, Los Angeles
Olinda. Brea CA
Toyon, Los Angeles CA
Penrose, Sun Valley CA
Bradley, Sun Valley CA
Industry Hills, Industry CA
Puente Hills. WhfttierCA
1984 Cinnaminson, NJ3
1983 Azusa, CA
SchoD Canyon. CA
Duarte, CA
Sheldon-Arteta, CA9
North Valley. CA3
Monterey Park. CA3
1. Notation and abbreviations:
MW • Megawatts electrical capacity
IC • Reciprocating internal combustion engine application
GT • Gas turbine application
ST - Steam turbine/electric
SH - Space heat application
PH - Process heat application
HBtu - High Btu for pipeline use
mmcfd - Nominal extraction rate of landfill gas, million cubic feet per day
2. Also described in more detail in this report
3. Facility currently shut down
Capacity and
ADDlicatlonl
1.7MW.IC
1.3 MW, GT
1.3MW, IC
0.9 MW, GT
1.3 MW, IC
4 mmcfd, SH
5 MW, IC
9 MW. IC
8 MW, IC
3 mmcfd, PH
SH
50MW.ST + 3MW, GT
PH
PH
IC
2 MW, IC
1.1 mmcfd
HBtu
p irt ft
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• A description of gas extraction from the Stone 1 Landfill and its uses. Uses include
fueling a cement kiln, process heat for metals refining, process drying of chalk powder,
and fueling Degeneration by an 1C engine. Information is contained in Robinson, 1990.
Reports on these and many other British landfill gas projects are found in the U.K. Landfill Gas Energy
Users Bibliography (British Library Document Supply Center).
5.8 Other Supplemental Literature
Three supplemental texts are included in appendices L, M and N. These became available too late to
include them in preceding sections of the report.
The text The Economics of Gas Recovery Systems in the United States" by George Jansen, is included
as appendix L. (This work was presented in Melbourne, Australia on February 27, 1992.) It provides
information and perspective on many issues covered earlier in this report from the viewpoint of a
significant developer of landfill gas systems (Laidlaw Gas Systems). In particular, additional information
is provided on internal combustion engine system economics, rate of return criteria, recovery project
histories, and energy and economic trends. Appendix M presents the text of "Waste Management of
North America, Inc. Landfill Gas Recovery Projects" by Michael Markham. This work was presented at
the SWANA 15th Annual International Landfill Gas Symposium, March 24 to 26, 1992. It documents
experience and operating philosophies of Waste Management of North America, Inc. (WMNA), the largest
U.S. operator of landfill gas energy systems, at its 25 U.S. energy projects. Appendix N, "I-95 Landfill
Gas to Electricity Project Utilizing Caterpillar 3516 Engines" describes a recently constructed facility using
Caterpillar 3516 engines, which are engines adapted for low-pressure gas, and particularly landfill gas,
use.
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6. REVIEW, COMMENTARY, AND CONCLUSIONS
This report has presented case studies of projects where landfill gas has been used, generally
successfully, in energy applications. It has also attempted to present an overview of the important issues
regarding landfill gas energy uses, and (within existing constraints) a brief review of costs and other
economic aspects. Some major conclusions can be offered based on this report's review and case study
work. Technical areas can be identified where work on obstacles appears most likely to advance landfill
gas energy use. The findings of this report also provide a context in which to review suggestions (by
others) for facilitating landfill gas energy use by addressing nontechnical barriers.
6.1 Conclusions
Major conclusions from this report are as follows:
• Landfill gas can be a satisfactory fuel for a wide variety of applications, and its use in
these applications provides environmental and conservation benefits. Many types of
energy equipment that operate on more "conventional" fuels can also operate on
landfill gas.
• Some reduction in the energy output of conventional equipment, of about 5 to 20
percent compared to Hs output on conventional fuels, is normally associated with
landfill gas use.
• When landfill gas is used as a fuel, its properties, unique nature, and particularly its
contaminants, must be considered. Many pitfalls are possible in landfill gas energy
applications. Especially important are equipment damage from the gas contaminants,
and gas supply problems such as shortages resulting from incorrectly estimating the
availability of the gas.
• Cleanup stringency and methods vary widely. The necessary degree of landfill gas
cleanup has not been well established. Cleanup by methods such as refrigeration can
be expensive, both economically and in energy requirements.
• The optimum tradeoffs between cleanup stringency and the frequency of maintenance,
such as oil changes, are not well established.
• Collection technologies are developed but probably could be further improved.
• Methods of forecasting gas availability for new sites are available but could be
improved.
• Economics vary greatly; at some sites, economics may be excellent but at others,
economics are a major limitation. Economics now tend to preclude smaller scale uses
and remote site uses where electric power sale prices are tow and there are no other
convenient energy applications.
• Emission limits in some U.S. locations may also inhibit landfill gas energy uses despite
an environmental balance sheet that would generally appear to be strongly positive.
The case studies of this report, comprising three reciprocating internal combustion engine sites, one gas
turbine site, a site combining interval combustion engines and space heating, and one boiler site, have
illustrated some of the possible applications of landfill gas. Recognize that these studies are only
•snapshots," representing a small part of the total number of landfill gas energy projects and experience.
Nonetheless the case studies illustrate some of the particular considerations regarding landfill gas. and
support the conclusions presented above.
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6.2 Further Needs
Based on the above case studies and cited literature, further needs for landfill gas energy use appear to
include (as a partial list)
• Examining ways to improve and standardize gas cleanup for specific applications.
• Examining further the tradeoffs between approaches such as more stringent gas
cleanup and maintenance measures such as more frequent oil changes.
• Examining further the optimum operating parameters, such as the best oil, coolant,
and exhaust gas temperature for 1C engines.
• Examining and documenting further the appropriate engine and other equipment
design modifications to reduce current contaminant-related problems experienced with
landfill gas use.
• Improving technology in ancillary areas that relate to energy uses, such as forecasting
gas recoverability and improving gas collection efficiency and reliability.
• Developing and improving economic small-scale uses for the landfill gas.
• Developing further detailed documentation of experienced problems, and attempted
and successful solutions to them, to benefit the community of present and future
landfill gas users.
• Examining ways to reduce economic (and institutional) barriers to landfill gas energy
applications. Further discussion of this issue is presented below.
6.3 Facilitating Landfill Gas Energy UM
Increasing collection and energy use of landfill gas would have consequences considered positive, as
outlined in earlier sections (this is also reflected in the various regulations cited in this report regarding
landfill gas). Technical obstacles remain, and technical improvements as outlined above should obviously
help advance landfill gas uses. Nontechnical barriers appear, however, to be as important as the
technical. As illustrated in section 4, high costs can combine with low energy sale prices at specific sites
to make energy applications of much landfill gas that is generated uneconomical. Barriers can also be
posed by other factors such as local emissions limits. Most gas generated by landfills is probably not yet
being used for energy because of such reasons (although precise statistics are not available) with
economics the dominant barrier. Incentives have therefore been recently recommended (as opposed to
approaches such as mandated energy use). They were favored by expert groups such as the
participants in the U.S. Environmental Protection Agency/Japan Environment Agency Workshop on
Methane Emissions and Opportunities for Control (U.S. EPA/JEA, 1991) and an earlier workshop by the
U.S. Environmental Protection Agency and the U.S. Department of Agriculture (U.S. EPA/USDA, 1989).
Some regulatory incentives now exist; federal facilitation is provided by tax credits under section 29 of the
Code of Federal Regulations. The examples of policies in Michigan and Illinois that result in more
favorable prices to landfill gas fueled electric generation are mentioned in appendix D. Some of the other
suggestions worth noting that have been made for overcoming economic and other nontechnical barriers
are as follows:
• Improving current federal tax credits and furthering state regulations benefitting landfill
gas energy users (Workshop participant conclusions, U.S. EPA/JEA. 1991).
• Allowing greenhouse gas and NMOC emissions "offsets' for landfill gas energy use.
(Conclusions of workshop participants, U.S. EPA/JEA, 1991).
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• Using environmental "balance sheets" for landfill gas energy conversion that consider
the total picture: not only the secondary emissions that tend to be the current focus of
local and other regulations, but also the wider benefits to the environment by reducing
radiath/ely forcing gas and other emissions and conserving other energy resources.
Workshop conclusions in U.S. EPA/JEA (1991), state that "incentives should reflect the
environmental benefits that will accrue from the implementation of the technologies
and practices.*
• Imposing a "methane tax" on decomposable waste that is landfilled, as suggested in
Augenstein (1990). This would provide funding toward methane abatement, and could
be preferentially collectible if the methane were abated through energy use. This
option is akin to the "carbon tax" that is suggested on fossil fuels as a way of reducing
their use and greenhouse CO2 emissions.
• Supporting landfill gas energy uses with a levy on fossil fuel use (reflecting the
emission consequences of fossil fuel use) similar to the British non-fossil-fuel-
obligation (NFFO) (Richards and Aitchison, 1990)
• Creating goals for nonfossil energy production (Workshop Participant Conclusions,
U.S. EPA/JEA, 1991).
Implementing any of these suggestions involves judgements on the valuation of various environmental
benefits, relative to costs, and policy decisions, that must be made elsewhere. The pertinent factor to
note is simply that these approaches would appear appropriate as means for facilitating landfill gas
energy uses in the context of this report's findings.
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EPA-530-SW-90-042(NTISPB90-215112). June.
Koch, W.R. 1986. A New Process for the Production of High-Btu gas. Proceedings from the GRCDA
9th Annual International Landfill Gas Symposium. GRCDA/SWANA. Silver Spring, Maryland.
Leeper, J. 1986. 40 kW Fuel Cell Experiment at Industry Hills. Proceedings from the GRCDA
9th International Landfill Gas Symposium. GRCDA/SWANA. Silver Spring, Maryland.
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, California. June.
McDonald, S. 1984. Medium Btu Landfill Gas Utilization at a Wastewater Treatment Plant. Proceedings
from the GRCDA 7th International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
Myers, J.D. 1987. The Marina, California Landfill Gas Fueled Electric Power Project. Proceedings of the
GRCDA Annual International Solid Waste Symposium. SWANA. Silver Spring, Maryland.
Nielsen, D. 1984. Small Electric Generation Projects. Proceedings from the GRCDA 7th International
Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
Piccot, S. and M. Saeger. 1990. National- and State-level Emissions Estimates of Radiatively Important
Trace Gases (RITGs) from Anthropogenic Sources. EPA-600/8-90-073 (NTIS PB91-103572).
October.
Richards, K. and E.M. Artchlson. 1990. Landfill Gas: Energy and Environmental Issues. Conference
Proceedings, Landfill Gas: Energy and Environment *90. United Kingdom Department of Energy
and United Kingdom Department of Environment. Oxfordshire, United Kingdom.
Robinson, M.G. 1990. Landfill Gas; Its use as a Fuel for Process Firing and Power Generation.
Conference Proceedings, Landfill Gas: Energy and Environment "90. United Kingdom Department
of Energy and United Kingdom Department of Environment. Oxfordshire, United Kingdom.
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Rosen, J. 1990. Running on Methane. Mechanical Engineering Magazine. May.
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). January.
Schlotthauer, M. 1991. Gas Conditioning Key to Success in Turbine Combustion Systems Using Landfill
Gas Fuels. GRCDA/SWANA's 14th Annual Landfill Gas Symposium. SWANA, Silver Spring,
Maryland.
Thometoe, S.A. 1992. Landfill Gas Recovery/Utilization—Options and Economics. Sixteenth Annual
Symposium on Energy from Btomass and Wastes. Institute of Gas Technology, Chicago.
Thometoe, S.A. and R.L Peer. 1991. EPA's Global Climate Change Program—Global Landfill Methane.
Air and Waste Management Association Annual Meeting. Vancouver, B.C. June.
U.S. EPA. 1991. Office of Air Quality Planning and Standards. Air Emissions from Municipal Solid
Waste Landfills—Background Information for Proposed Standards and Guidelines
EPA-450/3-90-011 a (NTIS PB91-197061). March.
U.S. EPA/JEA. 1991. (U.S. Environmental Protection Agency in cooperation with Japan Environmental
Agency). Methane Emissions and Opportunities for Control. Workshop results of
Intergovernmental Panel on Climate Change. U.S. Environmental Protection Agency, Washington
D.C. EPA/400/9-90/007.
U.S. EPA/USDA. 1989. (United States Environmental Protection Agency in cooperation with the U.S.
Department of Agriculture). Workshop held on greenhouse gas emissions from agriculture.
December 12-14. U.S. Environmental Protection Agency, Washington, D.C.
Vaglia, R. 1989. Operating Experience with Superior Gas Engines on Landfill Gas. Proceedings from
the GRCDA 12th Annual International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
June.
Van HeuH. R. and J. Pacey. 1987. The Gas Field Test: Design, Installation and Maintenance.
Proceedings of the GRCDA Annual International Solid Waste Symposium. SWANA. Silver Spring,
Maryland.
Watson, J.R. 1990. Pre-Treatment of Landfill Gas. Proceedings from the GRCDA 13th Annual
International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
Wans. R.A. 1987. The Justification of Landfill Gas Recovery for Electric Generation. Submitted Papers
and Abstracts for the GRCDA 10th International Landfill Gas Symposium. SWANA. Silver Spring,
Maryland.
Yeung, D.C. 1984. Small-scale Medium Btu Project, Cinnaminson, New Jersey. Proceedings from the
GRCDA 7th International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
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APPENDIX A
ESTIMATING GAS AVAILABILITY FOR ENERGY USES
Knowledge of the gas quantity likely to be available over time is critical for determining possible and
appropriate energy uses and sizing equipment; this appendix presents a limited discussion of approaches
to prediction. Note that the available gas is the generated gas, multiplied by the recovery efficiency
(confusion often exists on this issue, or at least with the terminology).
Although existing knowledge is far from complete, for much of the waste in the U.S. the methane
generation potential has been estimated as likely to be between 1 and 2 cubic feet per pound of total
waste on a dry basis (in metric terms, 62 to 125 liters/kilogram, [I/Kg]) as stated in Augenstein and Pacey
(1991). Similar estimates are given by Bariaz and Ham (1990) and Bariaz et al. (1990). Most of this gas
will be generated over a period of 10 to 40 years after filling; this also corresponds to various rules of
thumb that methane generation rates from wastes during the decade or so after placement may range
from 0.04 to 0.2 cubic feet per pound of dry waste per year (EMCON, 1982; Van Heuit, 1986). The
recoverability of this generated methane for energy use is most likely to lie between 50 and 90 percent.
Generalizations such as above leave wide bounds on possible gas availability, and are of little value in
sizing energy equipment, but the gas availability can be determined more precisely (and more usefully) by
modeling, field pilot tests, or a combination of these. Without an in-place extraction system, or
information from sources such as pilot tests, modeling techniques using waste placement and other
appropriate data can still be used to develop de novo estimates of gas generation over time. The
advantage of model projections is a cost typically less than 10 percent of field testing approaches. Work
by various investigators has resulted in the development of several such models for predicting methane
recoverability (EMCON, 1982; Van Heutt, 1986; Zison, 1990; and Augenstein and Pacey, 1991). Gas
generation does appear to be predictable, within limits, by the models but, unfortunately the error limits
are large; generation predictions are consequently often expressed as a range (commonly upper and
lower bounds are separated by a factor of two). The imprecisions that affect forecasts of gas availability
come from several sources, including the difficulties in assessing the types and quantities of waste that
were initially landfilled, temperature, moisture content, and many other critical variables (as listed in
Augenstein and Pacey, 1991). Work to refine available models does not appear to have been extensive,
although such work is now being undertaken as described in Thomeloe and Peer, 1991.
In addition to assessing the likely gas generation by modeling, pilot extraction tests may also be
conducted over a limited portion of the landfill area (EMCON [1982], Biezer et al. [1985], and Woodfill and
Bamum [1985]). Such tests are also inherently and sometimes seriously imprecise H extrapolations for
the total landfill are made based on a few wells. Sources of error include, for example, inability to readily
determine the volume from which a well, or groups of wells, is actually extracting, and the variabilities of
gas generation over an inherently heterogeneous fill. Interpretations of models and small-scale field
extraction tests require correction factors that tend to be site-specific and often have judgement
components.
Once a gas extraction system has been installed (see next) and has been functioning long enough for a
steady-state near-maximum recovery rate to be reached (depending on tuning and other factors, this is
usually a few months), gas recoverability information will be reasonably precise and the available
recovery results can be used to refine model predictions into the future. Models can be refined as
discussed in Zison (1990) and Augenstein and Pacey (1991).
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REFERENCES TO APPENDIX A
Augenstein, 0. and J. Pacey. 1991. Landfill Methane Models. Proceedings from the Technical Sessions
of SWANA's 29th Annual International Solid Waste Exposition, Cincinnati 91. SWANA. Silver
Spring, Maryland. September.
Bartaz, M.A. and R.K. Ham. 1990. The Use of Mass Balances for Calculation of the Methane Potential of
Fresh and Anaerobically Decomposed Refuse. Proceedings from the GRCDA 13th Annual
International Landfill Gas Symposium. SWANA. Silver Spring. Maryland.
Barlaz, MA, R.K. Ham, and D.M. Schaefer. 1990. Methane Production from Municipal Refuse: A
Review of Enhancement Techniques and Microbial Dynamics. Critical Reviews in Environmental
Control, 19. (This paper points out laboratory support for a yield near 2 cubic feet of methane per
pound, but that the maximum measured methane recovery from a landfill is, to date, near 1 cubic
foot per pound.)
Biezer, M.B., T.D. Wright, and D.E. Weaver. 1985. A Field Test Program for Determining Landfill Gas
Recovery Feasibility. Proceedings From the GRCDA 8th International Landfill Gas Symposium.
GRCDA/SWANA. Silver Spring, Maryland.
EMCON Associates. 1982. Methane Generation and Recovery From Landfills. Second Edition, Ann
Arbor Science. Ann Arbor, Michigan.
Thometoe, S.A. and R.L Peer. 1991. EPA's Global Climate Change Program—Global Landfill Methane.
Air and Waste Management Association Annual Meeting. Vancouver, B.C. June.
Van Heuit, R. 1986. Estimating Landfill Gas Yields. Proceedings from the GRCDA 9th Annual
International Landfill Gas Symposium. GRCDA/SWANA. 1986.
Woodfill, PA and M.F. Bamum. 1985. Management of Gas Extraction Systems. Proceedings from the
GRCDA 8th International LandfiO Gas Symposium. GRCDA/SWANA. Silver Spring, Maryland.
Zison. S. 1990. Landfill Gas Production Curves: Myth vs. Reality. Presentation at SWANA Annual
Meeting. Vancouver, B.C. SWANA, Silver Spring, Maryland.
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APPENDIX B
GAS EXTRACTION SYSTEMS
Gas extraction systems are a complex topic; only a brief overview is given in this appendix. Much
literature is available and ample detail can be found elsewhere (some starting points can be found in
EMCON, 1982, and Poland, 1987).
The overall concern of the gas energy user is that the gas system will continue to deliver a reliable supply
of gas, in the needed quantity, and that problems with the gas system will not reduce the output of, nor
shut down the energy equipment. Collection efficiency is also a concern.
As an overview, gas extraction systems suitable for energy applications typically employ vertical wells or
horizontal trenches to collect the gas from the mass of the landfilled waste. These are connected by
laterals to a main header that ultimately carries the gas to the energy equipment. Vacuum is nearly
always used to extract the gas. Several design considerations are important in assuring that the gas
system functions correctly, including the most basic one of sizing pipes adequately for gas flow, and
allowing for subsidence effects, draining condensate from lines to prevent its buildup, and allowance for
accessibility to the system for leak detection and repairing breaks.
The overall extraction efficiency is typically affected by well spacing, and the permeability of the cover
layer, typically the final cover. Collection efficiency is variously increased by reducing well spacing, and
decreasing the permeability of the cover layers. It must be emphasized, however, that if the cover is at all
permeable (and It almost always is), collection efficiency cannot, even in theory, be 100 percent with well
systems as currently designed: economic limits on well spacing and other factors limit collection efficiency
to levels that are more typically between 50 and 90 percent. Well spacing and depth are important
issues; readers reviewing literature win note that the concept of "radius of influence' is often cited with
respect to spacing wells. Within this radius, gas is assumed to be extracted by the well: outside this
radius gas is assumed to be not extracted. However, problems with this concept have also been pointed
out, in that the pressure influence of extraction changes gradually with the radius, and that the radius of
influence is therefore difficult to define and apply (EMCON, 1982). (This comment is presented so that
readers will be aware that differing opinions exist on both the radius of influence topic and others.)
Once the gas system Is installed. It is adjusted (tuned") to maximize recovery. Typical tuning involves
gradually increasing extraction rates from wells over time, until falling wellhead methane levels indicate
that air entrainment through the landfill surface, and into the collected gas, is significant. (Too much air
entrainment limits gas extraction since it can alter methane generation rates unpredictabty and
undesirably, reduce gas usability for energy because of dilution, or even cause the landfill to ignite.) If
methane production falls too far, the well must be throttled. The lag time between adjustment and
attainment of the final equilibrium composition is significant, and overshoots and undershoots are
common enough that tuning must often continue until several interstitial void volumes of gas are
extracted, or for several months.
A more recent approach, which has only had limited application, uses the pressure drop across the cover
as an indicator of extraction efficiency and to enable adjustments (Zison, 1990). This has the advantage
in principle of enabling more accurate and rapid adjustments.
Oversizing the energy equipment because of too-optimistic gas availability estimates is one of the more
common problems in landfill gas energy projects: gas estimates in such cases usually come from
modeling or field pilot tests made without a full gas recovery system in place. When energy equipment is
then installed (concurrently with the necessary gas system) the gas supply is found to be less than is
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needed. Installing the gas recovery system, determining availability as outlined above, and then installing
the energy equipment would appear to be a preferred course to avoid such problems.
This has been very limited summary of gas extraction equipment, practice, and associated issues; the
reader is referred to EMCON (1982), Poland (1987), and U.S. EPA (1991) for more detailed descriptions
of extraction systems. The topic of collection systems and practice is important because difficulties with
collection systems are also among the most common causes of problems with energy facilities.
REFERENCES TO APPENDIX B
EMCON Associates. 1982. Methane Generation and Recovery From Landfills. Second Edition. Ann
Arbor Science. Ann Arbor, Michigan.
Poland, R.J. 1987. Collection Systems for Landfill Gas Recovery and Control—One Size May Not Fit All.
Submitted Papers and Abstracts for the GRCDA 10th International Landfill Gas Symposium.
SWANA. Silver Spring, Maryland.
U.S. EPA. 1991. 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). March.
Zison, S. 1990. Landfill Gas Production Curves: Myth vs. Reality. Presentation at SWANA Annual
Meeting. Vancouver, B.C. SWANA. Silver Spring, Maryland.
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APPENDIX C
COMMENTS ON ENVIRONMENTAL AND CONSERVATION ASPECTS OF
LANDFILL GAS ENERGY USE
Landfill gas energy use clearly has economic consequences, which in successful cases will include
benefits to both energy producers and recipients of the energy. Using landfill gas for energy is also
associated with significant environmental consequences, considered predominantly beneficial; these are
best seen from the standpoint of the consequences if landfill gas emissions are not controlled.
If control is not attempted, the generation/emission of landfill gas poses some immediate hazards. Risks
include fire and explosion from migrating gas, at the landfill itself, or In structures on adjacent properties,
as well documented in Geyer, 1972 and U.S. EPA, 1991. The gas poses asphyxiation risks, since it may
enter culverts, or other enclosed spaces. Concerns about these hazards were the impetus for many of
the eariy gas control systems; many were simply barriers, such as trenches, to prevent gas migration,
although some included extraction.
The next concerns that developed, first in areas of the country with air quality problems (such as the Los
Angeles Basin), were those regarding emissions of the nonmethane organic compounds (NMOCs),
reactive organic gases (ROGs), or ozone precursors contained in the landfill gas. Various estimates of
the magnitude of these emissions have been presented, but at whatever magnitude may be correct, they
are significant (U.S. EPA. 1991). Concern over these has risen steadily to the present and further
discussion of air quality impacts and regulations is presented elsewhere in this report.
The final concern regarding landfill gas, from a global standpoint and over larger time periods, is its
potential contribution to changes in the earth's climate (Thometoe and Peer, 1990; Augenstein. 1990).
Interest in this issue has increased sharply over the last few years. This interest relates to the continuing
atmospheric buildup of 'greenhouse' gases, of which one of the most important is methane. Whatever
the details, tt is expected that if current trends continue some climate change should occur (although
timing and magnitude are uncertain) and some consequences could ultimately be serious (Houghton and
Woodwell, 1989).
Landfill methane's significance to climate change arises because the radiative forcing ("heat blanketing")
effect of methane, as a greenhouse gas, is about 25 times that of an equal volume of CC^. Enough
waste is landfilled annually in the U.S. that conversion of even a modest fraction of the landfilled organic
material to methane in landfill gas, which is then evolved to the atmosphere, contributes significantly to
the ongoing increase of global 'heat blanketing" or radiative forcing that is due to greenhouse gas
buildup. Estimated landfill methane emissions in references that include U.S. EPA (1991) and
Augenstein (1990) typically range from 3 to 20 teragrams per year (Tg/year) for U.S. landfill methane
emissions to the atmosphere. Based on atmospheric modeling, even a tower estimated range of
emissions of U.S. landfill methane of 3 to 8 Tg/year could be making a difference of 1 to 2 percent in the
earth's annual increase in total greenhouse gas radiative forcing (Augenstein, 1990).
The collection and destruction of landfill methane, whether through energy use or other routes,
ameliorates hazards and nuisances mentioned earlier and obviously prevents its emission into the
atmosphere; it results in a reduction in NMOC emissions, and any global warming consequence that
would otherwise occur from that methane. Emitted methane's greenhouse potency—compared to the
C02 that would result from burning that same methane—depends on atmospheric residence time, and
other factors. Considered from the standpoint of time intervals of up to 40 years, the combustion of
methane to CO2 has been calculated to reduce the greenhouse impact (radiative forcing) that would
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otherwise occur from it by over 90 percent (Augenstein, 1990). In that work the economics of landfill
methane abatement (without necessarily using the gas for energy) were found quite attractive (1 to
10 percent as expensive per unit radiative forcing benefit) compared to other approaches—photovoltaic or
nuclear for coat—whose costs could be identified (Augenstein, 1990). Similar conclusions, that landfill
methane abatement is one of the tower cost United States approaches to address potential climate
change problems, have been reached by a recent study by the National Academy of Sciences (1991).
While landfill methane extraction and abatement appears attractive as an approach to global warming to
the extent that it can be practiced—an economic "fix" to the landfill methane component of the
problem—using methane for energy has additional benefits. The energy use itsetf will typically offset
fossil fuel use elsewhere, reducing net CO2 emissions to the atmosphere (fossil fuels, usually oil, are the
"swing" fuels whose use is most typically displaced). When energy and other methane recovery-related
revenue depend on efficient collection of the gas that is generated, it is also reasonable to assume that
recipients of the resulting revenue will make efforts to maximize collection efficiency. The economic
incentives likely facilitate the attainment of environmental benefits (as reduced methane emissions).
Using landfill gas for energy also uses an asset that would otherwise be wasted, and the beneficial
energy use therefore represents conservation. Although estimates of landfill gas energy potential cited in
section 1 were "only" about 0.2 to 1 percent of the energy total used in the U.S., this quantity of energy is
still highly significant by most standards—equivalent to the total energy requirement of half a million to
possibly well over a million U.S. citizens.
Although the results of using landfill gas for energy can be considered primarily beneficial, some negative
consequences can be of concern. These are principally the emissions from the energy uses; the most
significant negative impacts (affected by regulations) are oxides of nitrogen (NOx) and carbon monoxide
(CO); NOx is the most important and can be a limiting factor. On balance, however, the benefits of landfill
gas energy use do appear to outweigh the negatives. Emissions and other regulatory issues are
addressed in elsewhere in this report.
REFERENCES TO APPENDIX C
Augenstein, D. 1990. Greenhouse Effect Contributions of United States Landfill Methane. Proceedings
from the GRCDA 13th Annual International Landfill Gas Symposium. GRCDA/SWANA, Silver
Spring, Maryland.
Geyer, JA 1972. Landfill Decomposition Gases. An Annotated Bibliography. US. Environmental
Protection Agency, Office of Research and Monitoring. Solid Waste Research Laboratory,
Cincinnati. EPA SW 72-1 -1 (NTISPB 213487). June.
Houghton, RA and G.M. Woodwell. 1989. Global Climatic Change. Scientific American. April.
National Academy of Sciences. 1991. Policy Implications of Global Wanning. National Academy of
Sciences. Washington, O.C. April.
Thomeloe, SA and R.L Peer. 1990. 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.
U.S. EPA 1991. Office of Air Quality Planning and Standards. Air Emissions from Municipal Solid
Waste Landfills—Background Information for Proposed Standards and Guidelines.
EPA-450/3-90-011 a (NTIS PB91 -197061). March.
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APPENDIX D
REGULATORY ISSUES WITH LANDFILL GAS USE
Regulations are another area of complexity, for which this appendix presents a brief overview with
historical notes. Regulations in several areas significantly affect landfill gas energy use. Some of these
regulations concern hazard and nuisance abatement, and air pollutant emissions reduction. Another
pertinent set of regulations are statutes, both state and federal, providing incentives to facilitate energy
applications and outlets for the produced energy.
In the history of landfill gas control regulations, regulations initially addressed the landfill-gas-related
dangers and nuisances (discussed in appendix C). These were followed by regulation, primarily local,
that addressed ROGs. (Earliest federal regulations did not normally directly affect landfills, except, for
example, as they favored landfilling over previous disposal methods for health and safety).
Some of the most pertinent current legislation on the national level is that of recently enacted
amendments to the federal Clean Air Act. Details of the proposed regulations, which as applied to
landfills are being finalized, are documented (Federal Register. May 30,1991). The primary purpose of
this legislation is to reduce emissions of NMOCs (ozone precursors), although other important objectives
exist (U.S. EPA, 1991). It is expected as a consequence of the proposed regulations that most of those
landfills capable of supporting energy systems, but that are now without any controls, will be required to
install gas recovery systems.
The proposed regulations prescribe the methods for determining whether landfill gas recovery is required
at specific sites, and the degree of NMOC abatement to be obtained with the recovered landfill gas. In
very brief overview, landfills established to emit 150 Mg or more a year of NMOC's are required to install
controls. Energy conversion equipment such as gas turbines, 1C engines, and boilers may serve for
control H equipment accomplishes 98 percent destruction of NMOC's or has 20 ppm or less of NMOC's at
the outlet. Performance testing is required to verify the degree of control. These are but summaries of
some key points; readers should consult U.S. EPA (1991) for full detail.
Many other state and local regulations exist regarding other landfill-gas-related issues, including
condensate disposal, effectiveness of gas migration control, and so on (Maxwell, 1989; Peterson, 1991).
Discussion cannot be presented here; the reader should simply be aware that such regulations exist and
are very likely to have significant impact on energy applications.
Some local emission regulations and regulatory guidelines are tending toward greater stringency than
federal standards, as exemplified by California's recent proposed guidelines (California Air Resources
Board, 1991). California's draft guidelines propose that energy conversion approaches must meet that
state's definition of best available control technology (BACT). Further discussion is omitted here except
to. note that such stringency may limit equipment and approaches (and could tend to reduce the amount
of landfill gas energy use).
The benefits of landfill gas energy use (see appendix C), in combination with a general congressional and
state intent to facilitate small-scale energy use, have resulted in legislation that helps facilitate market
acceptance for electricity produced from landfill gas (and similar sources) as well as legislation providing
credits and various incentives.
The provisions of the Public Utility Regulatory Policies Act (PURPA) are very important to those producing
electricity from landfill gas. PURPA allows producers of landfill-gas-fueled electricity in the U.S. to sell to
utilities at the utility's •avoided' cost, that is the sum of costs the utility would otherwise experience in
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terms of fuel, new plant construction, and other categories to produce the power. Provisions of federal
law are somewhat general with numerous accounting and costing methods possible; states such as
California have somewhat standardized the purchase agreements with "standard offers" (Hale, 1989) that
simplify the negotiation process.
The congressional wish to encourage alternative energy has also resulted in federal tax credit legislation
(Hatch 1991). This legislation provides a variable U.S. income tax abatement, or offset, credit with a
current (in 1991) value near 0.85/MMBtu for gas collected and sold for energy applications. The energy
application must be profitable for the credits to be realized, and there are other constraints.
Some state legislation to facilitate landfill gas energy use also exists. Michigan law. for example,
specifies an avoided cost formula for sale of electric power by a landfill gas facility to a public utility that
gives a favorably high price; Illinois specifies that a utility must buy electricity generated from landfill gas
in a county at the same average rate at which it sells it to customers in the county (Greenberg, 1990).
Regarding the impact on landfill gas energy use, the control regulations, and in particular the Clean Air
Act regulations, will probably result in the installation of gas recovery systems at many landfills that could
support energy systems. The gas system required for energy could thus be regarded as a "given" and in
the energy economics would not necessarily need to be accounted for as an expense against energy
production. The emission limits under the federal Clean Air Act were based on a review of currently
attainable equipment performance.
Regarding legislation that facilitates landfill gas energy use. the energy use tax credits provide a benefit
that can favor various energy applications, for example by offsetting gas collection expenses. State
provisions are also obviously beneficial where they exist. PURPA provisions facilitate sale acceptance by
grids of the output of electrical cogenerators (note, however, that the sale price now available for landfill-
gas-cogenerated electricity has tended to fall for reasons including falling avoided fuel costs, utility
generating overcapacity, and a hotly competitive auction market in which other cogeneratten sources bid
to sell power to utility grids).
The restrictions on energy equipment emissions, on the other hand, as applied or developing in many
areas in the U.S., imply significant additional expenses on landfill gas energy uses. These emission
restrictions characteristically treat the landfill gas emissions as a tie novo source. This does not consider.
as part of an overall assessment, the environmental benefits such as more efficient NMOC emission
control and other consequences that occur due to energy applications. In particular, the energy
conservation, and also the offset effect of landfill gas energy use in reducing net emission of radiatively
forcing gases, is typically not now considered by state or local regulators.
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REFERENCES TO APPENDIX D
California Air Resources Board. 1991. Air Pollution Control at Resource Recovery Facilities. 1991
Update (Draft Document as of May 1991, contains proposed guidelines. Final expected in early
1992).
Federal Register, Vol.56, No. 104, Thursday, May30, 1991. Standards of Performance for New
Stationary Sources and Guidelines for Control of Existing Sources: Municipal Solid Waste
Landfills. Part III, p. 24468.
Greenberg, F. 1990. Selling Electricity to Utilities. Proceedings from the GRCOA 13th Annual
International Landfill Gas Symposium. SWANA, Silver Spring. Maryland.
Hale, B. 1989. California's Alternative Energy Program and Landfill Gas to Energy Projects.
Proceedings from the 12th GRCDA Annual International Landfill on Symposium. SWANA, Silver
Spring, Maryland.
Hatch, R. 1991. The Federal Tax Credit for Non-conventional Fuels: Its Status and Role in the Landfill
Gas Industry. GRCDA/SWANA's 14th Annual International Landfill Gas Symposium. SWANA,
Silver Spring, Maryland.
Maxwell, G. 1989. Disposal Options for Landfill Gas Condensate. Proceedings from the 12th Annual
International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
Peterson, E. 1991. Pending Subtitle D Regulations and Their Effect on Landfill Gas Issues. Proceedings
from SWANA's 14th Annual International Landfill Gas Symposium. SWANA, Silver Spring,
Maryland.
U.S. EPA. 1991. 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(NTISPB91-197061). March.
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APPENDIX E
GAS COMPOSITION ANALYSIS
In contrast to the case with more "conventtonar energy sources, landfill gas users may need to check the
composition of their fuel more or less regularly. Methane and energy content can change as the
consequence of extraction procedure, or other factors. Oxygen in the gas can indicate leaks that need
repair. Gas system tuning" is often needed to provide a gas stream of appropriate quality to keep energy
equipment running, and this tuning can require frequent well-by-well analysis. In addition the gas will
contain a range of contaminants, whose level varies with landfill, and over time. As composition can have
important energy consequences, gas composition analysis is reviewed briefly here.
Methane and oxygen content can be determined by various techniques of which the most common is a
portable meter combining thermal-conductivity-based methane analysis with electrochemical-cell oxygen
analysis (manufacturers include GasTech and MSA). This equipment has the advantage of speed and
portability. Greater precision is available through gas chromatography techniques. This equipment is
less portable and less frequently used, most often to sample the total gas stream supplied to the energy
application. A discussion of methodologies for methane and oxygen content analysis is presented in Van
Heuit, 1983. One "bottom-line' indication of gas quality is of heat of combustion, which may be checked
by on-line calorimetry.
Compositional analyses for gas trace components (all components other than methane, carbon dioxide,
nitrogen and oxygen) down to extremely low levels can be accomplished by a variety of methods
including gas chromatography/mass spectroscopy (for example as described in Gas Research Institute,
1982). Chlorinated hydrocarbons are usually the greatest concern because of equipment corrosion
potential (discussed elsewhere in this report); techniques for analyzing for these with portable equipment
are described in Zimmerman et al. (1985) and independent outside laboratories recommended by engine
manufacturers for chlorine content analyses are given in Chadwick (1989).
This is largely presented to provide awareness that analysis may be required to assure performance.
Interested readers should seek further information from literature, equipment manufacturers and/or
contact others with expertise on this issue.
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REFERENCES TO APPENDIX E
Chadwick, C.E. 1989. Application of Caterpillar Spark-Ignited Engines for Landfill Gas. Proceedings
from the GRCDA 12th Annual International Landfill Gas Symposium. GRCOA/SWANA, Silver
Spring, Maryland.
Gas Research Institute (GRI): Landfill Methane Recovery. Part II: Gas Characterization. Final Report
(1982). Gas Research Institute, Chicago.
Van HeuH, R. 1983. Extraction, Metering, and Monitoring Equipment. Proceedings of the GRCDA 6th
International Landfill Gas Symposium. SWANA. Silver Spring. Maryland.
Zimmerman, R.E., R. Stetter. L. Alpeter, and N. Flynn. 1985. On-line Monitoring for Trace Compounds in
High Btu Gas Streams. Proceedings from the GRCDA 8th International Landfill Gas Symposium.
SWANA, Silver Spring, Maryland.
-------
APPENDIX F
COST, REVENUE, AND OTHER ECONOMIC COMPONENTS: DISCUSSION
Readers must recognize how site-and-situation specific landfill gas energy economics can be; the site-to-
site variation in capital and operating cost were reviewed in the main text. Development or presentation
of detailed process economics are beyond this report's scope. It is possible, and can be helpful, however,
to review some more commonly encountered components of energy systems (whether electrical or other)
with some discussion, where possible, of cost basis and reasons for variation over typically experienced
ranges. The discussion to follow addresses, in turn, capital and related costs, operating and maintenance
costs, and revenues and other benefits.
Capital cost Hems
•Capital cost" for equipment can have various definitions. It is convenient here to use the installed cost,
defined as including the total burden of engineering, installation, and permitting as well as other cost (as
well as these can be estimated and allocated) to arrive at the total cost for a functional plant equipment
component. Capital cost will be expressed either for the total for a site, or in terms of the normal capacity
units of the equipment, such as cost per kW or Btu/hr. (For interested readers wishing to translate cost
components from one basis to another, note that 1 dm of landfill gas corresponds to about 2 to 3
kilowatts, 20 to 25 pounds per hour of steam, or about 500,000 to 650,000 Btu per day of space heat.)
Capital costs for frequently encountered items or categories using the definition above are as follows:
Gas system. Gas system costs will be likely to lie between $200 and $2,000 per standard cubic foot per
minute (scfm) of landfill gas, based on recent SWANA and U.S. EPA cost data (SWANA, 1991; U.S. EPA,
1991). ($1.00/scfm landfill gas will correspond to about $0.40 to 050 per kW of electrical capacity or
$0.035 to $0.05 per pound per hour of steam, or $1.30 to $1.50 per million Btus per day of process heat
when energy equipment is continuously on-line. Thus for the cited figures it may be worked out that the
gas system costs may lie roughly at $80 to $lOOO/kW electric capacity, $7,000 to $100,000 per pound per
hour of process steam, or $250 to $3,000 per million Btu per hour of peak space heating capacity.) The
costs tend to rise relatively slowly with size, that is, gas systems become more economic per unit
throughput as scale increases.
This cost might or might not be allocated to the energy application, depending on whether the system
would be required in any event without the energy system (see discussion in appendix 0 for Clean Air Act
implications).
Gas cleanup. Landfill gas cleanup system costs can be extremely variable and, based on experienced
costs, would appear to range from as low as $5 to well over $100 per cubic foot of landfill gas flow per
minute (corresponding roughly to $10 to $500/kW for electrical applications). Part of the reason for this
variability Is that needs vary by site. Also, in the absence of knowledge about what type or degree of
cleanup is most cost-effective, a wide range of equipment is applied.
Condensate removal and treatment. The costs for this, on an incremental basis, can be small if the
condensate can be returned to the landfill or combined with leachate flow, to which it adds a minor
volumetric increment. However handling costs may be higher in many areas where separate condensate
handling and treatment is required. No figures are immediately available but discussions of the issue are
presented in Maxwell (1989) and it is well for potential energy users to recognize this as a potential
expense; It is a cost component incurred if gas recovery is mandated, whether or not energy recovery is
PJG GB40101A AOW
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practiced. Like the cost of the gas system itself, is a cost that might be a "given" and not necessarily
expensed against conversion.
Energy equipment
Electric generation-reciprocating internal combustion (1C) engines. Electrical generation using these
engines has been to date the application for the majority of U.S. sites. Costs for complete, new
reciprocating 1C engine-generator sets would appear to lie in the range of $1000-2500/kW. This includes
the basic genset package (engine, turbocharger if used, and control systems) but excludes costs such as
those for interconnects presented elsewhere in this capital cost summary. Costs per kW fall with size, or
can be reduced if equipment is acquired used, as it has been for many sites.
Electrical generation using gas turbines. For combustion gas turbine-generator sets costs would appear
to lie between $2,000 and $3,000 per kilowatt.
Fuel cells future technologies." As a potential electrical generation technology, fuel cells come off wed in
terms of capital costs, with cost estimated to be under $2000/kW. However attainment of this will require
further manufacturing cost reduction from current levels, and validation of operation characteristics on
landfill gas, which is planned (Sandelli, 1992).
Interconnects with electrical utility grids (specific to electrical generation). These are another item whose
costs can vary widely; the range of variation within this report's case studies is from about $20/kW
(reported for Marina) to $500/kW (reported for Prince George's County). The reasons for variation
include whether the interconnect is one or two-way, the voltage step-up needed for power sale, the scale,
and of particular importance as many landfill sites are remote, the distance power lines must be run from
the generation site.
Boilers. Capital cost of boilers, where they are used, win vary with size, steam pressure and other
factors. Full cost data for boilers are not available, and landfill gas boiler applications are few, but for one
example (a case study described in this report), capital costs are about $25,000 per 1,000 pounds of
steam per hour, including all ancillary control equipment. This is but a single case, and it is likely that
boiler costs per unit capacity wilt vary substantially with circumstances. Qualifiers to cost issues are that
the case study cost included a building (not always a needed component) and that pipelining costs will be
extra (they are an additional $6,000 per 1,000 pounds of steam per hour for the case study site, on top of
the cited $25,000 per 1,000 pounds of steam per hour). Pipelining costs will probably be significant
because appropriate users of steam, If available, will often be some distance from the landfill.
As an overview, the capital cost of a boiler will be 10 to 20 percent of an engine-generator set that uses
landfill gas at the same rate, and with appropriate situations very attractive returns are posstote on their
relatively low capital investment. Specific capital cost information on boilers will be available from
vendors.
Capital costs of other energy technologies. Numerous other applications are possible for landfill gas (for
example process and space heating, vehicle fueling, and other applications as mentioned above) but
capital costs are so situation-specific that cost estimates wDI not be attempted here. The capital costs for
many of these technologies fueled by conventional fuels are available from manufacturers and other
sources. The recommended approach would be to obtain these costs on more conventional fuel sources
and then add to them the additional costs estimated as specific to landfill gas fueling.
Other capital cost categories. There are, in addition to cost items above, other situation specific and quite
frequently major capital costs. These can include rights to the landfill gas, or rights to favorable power
contracts. Other cost categories include pipeline costs and the costs for providing on-site utilities such as
water at remote sites. Power contracts and landfill gas rights can be evaluated in a present worth type of
evaluation, in terms of the extra return component over time expected from gas production or contract
Other comment will be omitted on these costs because of their variability except to note that such cost
components may exist and comprise large fractions of total capital cost.
r "
-------
Capital-related fixed costs
The capital-related fixed costs are charges related to the investment which can include interest on debt,
taxes, insurance, depreciation, and the like. They are the part of the energy cost that results directly from
the capital investment, and are proportional to the capital investment (which is why lower capital
investment is desirable). As capital costs are highly variable, fixed costs are likewise variable; in fact on a
percentage or ratio basis the fixed costs will be even more variable than capital costs (the greater
variability relating to interest rate variation and other factors).
(Note that fixed costs continue whether the facility is producing energy or not. Problems such as energy
equipment or gas system breakdown or other factors that result in lowered energy revenue can result in
failure to cover fixed costs, and serious financial problems. These can include, if not loss of investment,
loan defaults or worse.)
Operating costs
Only brief comment on operating costs will be given here. Detailed, publicly available data are limited
(and the case studies of this report may add somewhat to the existing body of publicly available
information).
Operating and maintenance costs can either be viewed against a baseline of operation of a similar energy
application on more conventional fuels, or as the cost of operation reported by the equipment operators in
terms of units of output. In contrast to capital costs, which can be broken out to a fair level of detail,
lumped operating costs are frequently reported for all of the equipment in the aggregate in an energy
application. They tend to be closely proportional to the energy production.
Gas system. Some of the factors in operation of gas systems are discussed in Augenstein and Pacey
(1991). Variables include landfill size, porosity of cover, frequency of tuning required, and objectives (i.e.
pipeline or low Btu gas extraction). Operation and maintenance costs will range from a low value of
around $30,000 per year to well over $200,000 per year.
Engine operation costs. The cost of operation and maintenance of reciprocating 1C engines on landfill
gas, compared to operation on more conventional fuels, is of interest because of the extent to which such
engines are used.
One industry observer has commented1 that the operating and maintenance costs of landfill gas fueled
engines increase very roughly by 25 percent compared to more conventional fuels. Clearly, the extra
cost will vary from engine to engine and site to she, (as It obviously does for engines operated by that
organization as documented in Vaglia, 1989). In addition relative cost will differ with cleanup
effectiveness. Nonetheless this number is one useful guideline estimated by an organization with
extensive experience in such operation.
The operation and maintenance costs of engines have also been reported as cents per kWh of electrical
output. One reference (Jansen, 1986) presents an averaged cost ol 133 cents per kilowatt hour for
generation scales of 500 to 1000 kW based on Gas Recovery Systems' (now part of Laidlaw Gas
Systems) experience, of which 0.0035/kWh is labor and the rest cost of an on-slte operator. This cost,
updated to the present, would imply a cost of about $0.02/kWh. One engine manufacturer has recently
detailed estimated life-cycle maintenance costs for an engine (its G7042GSI) on natural gas in deriving
1.1 megawatts of generation under "severe" operating conditions, defined as operating at maximum
continuous recommended load2. These costs, amounting to $0.0045 per kWh, do not include on-site
operator labor, or costs for maintenance of other aspects such as gas cleanup, that would be required at
a landfill gas facility. Operator labor at an assumed burdened cost of $50/hr full time and an engine
service factor of 80% would add $0.013/kWh to give a total of $O.Ol75/kWh. The gross totals of the
1 Personal communication, Stan Zson. Padfc Energy, to Susan Thometoe and Don Augenstein, March 1991.
2 Personal communication. Jeff Bafis. Waukesha. June 1991.
PJG GM0101A AOW
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Waukesha estimate and Jansen (1986) both imply current costs near 2 cents per kilowatt hour, which
would seem a representative benchmark for a scale near one megawatt. However variability in such
estimates is illustrated in that, between the estimates, both the labor and equipment maintenance
components vary threefold and are reversed.
Even for smaller electrical operations, it has been found to date that full-time on-site operators are stHI
required. Labor costs for such smaller scale operation are such that few electrical projects at 500 kW or
less can presently be viable.
Interconnect Often associated with electric power generation is the cost for an interconnect. If the
interconnect is utility financed, charges are levied for both operation and maintenance, and the utility's
fixed charges and return may be a total of about 2 percent of the capital cost per month.
Operation and maintenance costs for other equipment. There have been relatively few reported data for
landfill gas fueling of boilers, kilns, process heat applications and the like. In several cases for which
information is available (which include a boiler and space heating application presented in this report) no
operation and maintenance differences or cost associated with them could be identified. Operation and
maintenance costs for such specialty applications should in any case be derivable from the equipment on
conventional fuel with add-ons if established as necessary for operation on landfill gas.
In general, operation and maintenance costs are specific to scale, equipment, and site, and factors such
as gas contamination. They are dependent on the diligence with which maintenance is performed.
Compared to a basis of trouble-free operation on "clean" or pipeline gas, these costs will obviously
escalate sharply on a unit energy output basis when operating problems as described earlier are
encountered, which both increase costs and reduce output.
Royalties. Royalties are typically a variable cost levied as a fraction of the total gross energy revenue.
they are often zero and otherwise most typically in the range of 5 to 20 percent.
In theory, for a viable project, the sum of costs above should be below revenue, discussed next.
Revenue Components
Benefits that a project accrues can include cash sales of energy, costs avoided through displacement of
energy purchases, as well as ancillary benefits such as gas abatement and tax credits. A brief discussion
of these follows.
Cash sales of energy: electric power. Although electric power sales to the grid will be possible at the
majority of sites, the revenue for power sold varies widely. The "averaged* power sale rate for
continuous, constant-rate production that would occur uninterrupted over a year varies over the U.S. from
a low of approximately 2 cents per kWh (areas such as the Pacific Northwest), to over 10 cents (Hawaii).
Avoided costs: electric power. When landfill-gas-generated electricity is used in lieu of utility power from
the grid, electric utility retail costs are avoided. These "avoided cost' benefits are almost invariably higher
than the price for which the power could be sold to the utility. Avoided costs may be from 25 percent to
more than twice the price for direct sale of power to the utility depending on whether the utility requires
capacity or has a large amount of expensive generation operating. Averaged avoided costs for a
continuously generated electrical power stream consumed by a large user, depending on U.S. location,
will typically lie between 4 and somewhat over 10 cents per kWh. In any case, the benefit wPI typically be
greater than for sale to the grid.
Other energy sale prices. The sale price received for forms of energy other than electricity Is typically set
by the price of competing fuels. For example, at a current oil price of $20/barrel, or the equivalent
pipeline gas cost of slightly over $3/1,000 cubic feet, the sale price realized for landfill gas might be near
$3/1.000 cubic feet of methane content. In practice the sale price will vary depending on local price of
competing pipeline gas. and other additional costs or effects specific to landfill gas, but the percentage
variation in gas sale price across the U.S. would typically be much less than Is true of electricity. If a
o ift ft
-------
product such as steam or hot water is sold, the price might be 20 to 50 percent higher on a Btu basis than
the local price of competing fuels to reflect efficiency and cost of conversion.
Tax credit benefits. The Federal alternative energy tax credit is a benefit that may be available to an
independent entity ("provider) owning and operating the gas system, and providing the energy to a user
(user). The provider must be less than half owned by the gas user. A reduction of the provider's federal
income tax, up to the provider's tax total, is obtained under a formula based on the price of oil. The credit
is currently close to $0.85 per million Btus. Its effect on energy economics may be realized in various
ways; it is most often realized through the provider's subsidy of costs for gas system construction and
operation that would otherwise be a component of the energy cost. This is a major benefit, amounting to
slightly over $O.Oi/kWh for electrical generation. It would appear to have facilitated a large number of
projects.
Other miscellaneous benefits: gas system. Although the gas control system may be mandated by
regulations whether or not the energy is used, it is often convenient for the entity operating the energy
system to also participate in operating the gas system. This is because staff are available, and gas flow
and composition need to be analyzed for both gas system and energy equipment operation. When this
occurs, a major fraction of gas system operation costs that would otherwise be experienced (see above)
can be avoided; the allocation of such savings is typically a matter of negotiation among project
participants.
Total costs and overall economics
Total costs of a project including all components would be determined by summing capital, operating, and
maintenance costs in categories above. Economics would be determined by comparing the total of these
costs to the sum of the benefits. This report generally avoids presenting "the" economics by application,
because of wide variation and also partly for lack of data; the specific case of reported capital costs of
electric power facilities versus capacity has been addressed in the main text.
PJG GM0101A AOW
r r
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REFERENCES TO APPENDIX F
Augenstein, D. and J. Pacey. 1991. Landfill Methane Models. Proceedings from the Technical Sessions
of SWANA's 29th Annual International Solid Waste Exposition, Cincinnati <91. SWANA, Silver
Spring, Maryland. September.
Jansen, G.R. 1986. The Economics of Landfill Gas Projects. Proceedings from the GRCDA 9th
International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
Maxwell, G. 1989. Disposal Options for Landfill Gas Condensate. Proceedings from the 12th Annual
International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
Sandelfi, 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). January.
SWANA (Solid Waste Association of North America). 1991. Comments Submitted August 1991. The
Local Government Solid Waste Action Coalition (SWAC): The National League of Cities (NLC),
The National Association of Counties (NACo), The Solid Waste Association of North America
(SWANA). On the U.S. EPA's Standards of Performance for New Stationary Sources and
Guidelines for Control of Existing Sources—Municipal Solid Waste Landfills. Available from
SWANA, Silver Spring, Maryland.
U.S. EPA. 1991. Office of Air Quality Planning and Standards. Air Emissions from Municipal Solid
Waste Landfills—Background Information for Proposed Standards and Guidelines.
EPA-45(K3-90-011a (NTIS PB91-197061). March.
Vaglia, R. 1989. Operating Experience with Superior Gas Engines on Landfill Gas. Proceedings from
the GRCDA 12th Annual International Landfill Gas Symposium. SWANA. Silver Spring, Maryland.
June.
-------
X X X X X
1
m
p~
m
o
so
•—«
o
CT
N
PACIFIC ENERGY
t. IM>»«1CICM
uniMo not run
OUT ruNT
OUT. SAMIMT UMOnu.
or
-------
APPENDIX H
• c i r i« i • * • a r
EQUIPMENT DETAILS, OTAY FACILITY, PACIFIC ENERGY
NAME OF PROJECT: Otay Power Station
OWNER: Pacific Energy
BRIEF DESCRIPTION:
The Otay Power Station, located in Southern California on the County of San
Diego's Otay landfill in Chula Vista, generates electric power using gas
recovered from the landfill. The landfill gas (containing about 47%
methane) fuels a single internal combustion engine/generator to produce up
to 1.7 megawatts (MW) of net power which is sold to San Diego Gas &
Electric. The plant began operation in December 1986 and has a typical
availability factor (on line time) of over 90% including scheduled
maintenance.
KEY PROJECT DATA
Project Location Otay, California
Landfill Name Otay Sanitary Landfill
Landfill Owner County of San Diego
Gross Power 1,900 KW
On site Power Use 51 to 10%
Net Power to Grid 1,700 KW
Power Purchaser San Diego Gas t Electric
Eguiv. Homes Served 1,700 (maximum)
Barrels of Oil Saved/yr 22,000 Barrels (maximum)
Fuel Used Landfill Gas
Landfill Size 525 Acres
Landfill Depth 90 feet (current average)
Landfill Fill Rate 500,000 tons per yr.
Landfill Opened 1966
Landfill Closure beyond year 2000
Number of Gas Wells Thirty-two
Number of Engine-Generators..One
Type of Engine Gas fired, internal combustion, 16 Cyl
Type of Generator 1,875 XW 4,160 Volt, synchronous
Type of Transformer 4,160 Volt to 12,000 Volt, step-up
Project Start-Up December, 1986
Project Life (Estimated) 20 years
Project Operator/Owner Pacific Energy
Project Employees Total One
Project Employees 1st Shift..One
Project Employees 2nd Shift..Not required, automated operation
Project Employees 3rd Shift..Not required,'automated operation
XPANSION PLANS:
ne Plant will be expanded to incorporate an additional engine-generator
nd related equipment to double power output. Construction is to begin
3°ut April 1st. Start-up is scheduled for summer 1991.
m BcuJ»»on*. Cemn»rc». Calilomia 90040.1213) 7K-I133 FAXBi3;72*47T2
-------
Jlflfflsfc
r*c t r,c r • c • • r
OTA* POWER STATION (Key Components)
MOTOR CONTROL CENTER fMCC)
Contain* starter* and controls for all electrical actors at the power plant.
Including: Gas compressor, air compressor, gas cooler, water cooler, building
fan, etc.
GENERATOR SWITCH GEAR PANEL
Houses instruments and controls for the plant's generator (4160 Volt, 3 phase,
60 Hz).
AUTOMATIC DIALER
Provides automatic "dial-up" or page alert notification to plant operators in
the event of a plant shut-down. The system is programmed to provide a voice
synthesized message alerting the operator which component initiated the shut-
down.
DATA COLLECTION COMPUTER
Receives and stores information from the plant's gas chroma tograph, as well as
various transducers and thermocouples located throughout the plant. Computer
compiles various information and reports on plant production. All data and
reports produced at the plant can be accessed via a phone line link up to
Pacific Energy's headquarters office.
AIR COMPRESSORS f?\
Provides compressed air to operate plant instruments, pneumatic valves,
pneumatic pumps and for engine start-up.
GAS COMPRESSOR
Draws gas from landfill at a typical vacuum of 10" to 20" water column and
discharges gas at 100 psig to the engine. Electrical motor driven. 150
horsepower. Two stage reciprocating.
ENGINE
Internal combustion. 16 cylinders. Turbo-charged. 2650 Brake horsepower.
13,194 cubic inch displacement. 900 RPH. 85-90 psig inlet gas pressure.
ENGINE CONTROL PANEL
Houses instrumentation and controls for Cooper superior "Clean Burn* engine.
GENERATOR
Produces 1875 Kilowatts at 4160 Volts. 3 phase. Single Bearing.
Synchronous. 900 RPM.
CAS CYLINDERS
Contains Helium (Carrier gas) and reference gas mixture (Span gas) , for
calibrating the plant's gas chromatograph which measures and records the
percent of Methane (CH4), Carbon Dioxide (CO2), Nitrogen (N2) , Oxygen (02);
also calculates heating value (BTU/CF) .
CAS FILTER — INLET
Removes particulate and water from inlet gas to compressor.
ENGINE OIL FILTERS f21
Filters designed to remove oil particulate down to 10 to 15 microns.
of fresh oil for the plant's int.rnal combustion
engine. 1600 gallon. Manually operated.
KS^SgyStSS caused oil from the plant '. internal combustion
engine. 1600 gallon. Manually operated.
WATER STORAGE TANK
5000 gallon capacity.
SUBSTATION ,. - _ ...
owned and maintained by Pacific Energy. Steps-up voltage from Pacific
Sn!rgy*»pS!ir Plant from 4160 Volt, to 12.000 Volt, to match SDCtE's
transmission lines receiving the power. Station contains main transformer,
auxiliary transformer, air switches, and power measurement meters.
p __ , , rne.-v- OSS for Wo»hi-.7»r Boulevard Commerce CoWormo 90040 r2J*"2S-J/3S TAJf f?J3) 725-977?
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APPENDIX I
PG&E POWER PURCHASE RATES, MARINA-
Pacific tosBRdBtetrteCoapaay TTBeaieStreet
San Fnncsco.CA 94106
415/972-7000
ENERGY PRICES FOR QUALIFYING FACILITIES EFFECTIVE MAT I. 1990 - JULY 31. 1190
Th« energy price* applicable to purchases by PGIE from qualifying facilities «re shown belo*. They
ere the product of the weighted-average utility electric generation (UEG) natural gas rate and the
Incremental Energy Ratt* plus an adjustment for the revenue requirement for Cash Working Capital, tne
(eotnermal Adder and the Variable DIM Adder. The Incremental Energy Rates and the Variable OIK Adder
•ere adopted by the California Public Utilities Commission in Decision 89-12-015. The Geothermal
Adder was adopted In Resolution No. E-3139. dated July 19. 1989. The revenue requirement for Cain
Working Capital is calculated in accordance Kith Decision S9-12-057. The average UEG gas rate '»
based on the most recently adopted forecast of UEG volumes in Decision 90-04-021. the current uEC
transportation tariff as filed In Advice Ne. 1586-6 and the) natural gas commodity charge to core-elect
customers on the date of posting.
REVENUE
REQUIREMENT
FOR CASH
WORKING
CAPITAL
INCREMENTAL
ENERGY »ATE
ii/kH
WITH JlMf.QF.
DELIVEBT ne-»IM;»
•oak
Partial-Peak
Off-Peak
•Super Off-Peak
WITHOUT TIMF-OF-
DELIVERY METERTN6:
Seasonal Average
(Period A)
FOOTNOTES:
Blu/kWh*
(1)
9.290
1.04$
8.542
7.747
1.141
AVERAGE
U!6 MTE
S/MMBtu
(2)
3.3532
3.3532
3.3S32
3.3532
J/kWh
(3)
0.00012
0.00012
0.00011
0.00010
GEOTHERMAL VARIABLE
ADDER"" QtM ADDER
J/kWh S/kWh
(4) (5)
ENERGY
PURCHASE
PRICE'"
S/kWh
0.0004117
0.0004187
0.0004187
0.0004187
O.OOZ328
0.002328
0.002328
0.002328
3.3S32 0.00011 0.0004187 0.002328
0.034013
0.033189
0.031495
0.028819
0.031852
FEBIOP
PEAK:
PARTIAL-PEAK:
OFF-PEAR:
NAT
1 - OCTOBER 31
fPeriod Al
Noon
8:30 a.
8:00 p.
9:30 p.
5:00 a.
5:00 a.
1:00 p.m.
Noon
9:30 p.m.
1:00 a.m.
8:30 a.m.
1:00 a.m.
NOVEMBER 1 • APRIL 30
(Period 81
Rone
8:30 a.m. • 9:30 p.m.
9:30 p.m. - 1:00 a.m.
5:00 a.m. - 8:30 a.m.
5:00 a.m. - 1:00 a.m.
Monday • Friday, eicept holidays
Monday • Friday, except holidays
Monday - Friday, except holidays
Monday • Friday, exceot nolieays
Monday • Friday, except holidays
Saturday. Sunday and nolioays
SUPER OFF-PEAK: 1:00 a.m. • 5:00 a.m. 1:00 a.m. - 5:00 a.m. All days
(Holidays include New Tear's Day. Washington's Birthday, "eswrtal Day. Independence Day. Labor Day.
Veterans Day. Thanksgiving Day. and Christmas Day.)
••Incremental Energy Rate? are derived from PGIE's marg-nal energy costs.
•••The energy purchase price excludes the applicable ene-;y line loss adjustment factors. As ordered
by Ordering Paragraph Ne. 12(j) of Decision No. 82-12-:20. this figure is currently 1.0 for
transmission and primary Interconnection voltage lane's, and for secondary distribution is as
follows:
Period A Period 8
Peak
Partial-Peak
Off-Peak
Super Off-Peak
1.0140
1.0131
1.0093
1.0093
1.0119
1.0087
1.0087
••••On April 10. 1990. PSIE submitted Advice No. 1282-E-A to supersede Advice No. 1282-E and to
propose a Gee thermal Adder of $0.0004S!9/kWh. Advice No. 1282-E-A has yet to be approved by tne
CPUC. PG&E has requested specific CPUC authorization to apply the S0.0004519/ktfh aooer to en*-;,
payments for variable-priced energy purchased en and a'ter May 1. 1990.
TAR AOS40S p. 1
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APPENDIX J
SPECIFICATIONS FOR CLEAVER-BROOKS BOILER
rooks
Cleav
Packaged Boiler
. STEAM OR HOT WATER
OIL, GAS OR COMBINATION FIRED
COMPACT
EFFICIENT
PERFORMANCE PROVED
UNEOUALED FUEL ECONOMY: Four
pass, forced draft construction: efficient
burner design:
Guaranteed minimum 80% fueUo-
steam efficiency from 25 to 100% of
rating on either gas or oil fuels.
Guaranteed minimum fueMo«steam
efficiency at 100% of rating is 82.0%
with gas firing and 83.0% with oil firing.
EASY MAINTENANCE: Hinged or davited
doors; modular control panel, retractable
burner nozzle.
QUIET: Sound levels are lower than strict
hospital and school standards due to
unique caseless fan design. Less than 68
db in high fire — less than 85 db in low
fire when measured on the "A" scale.
HEATING SURFACE: 3500 sq. ft. on the
fireside — 3800 sq. ft. on the waterside.
AUTOMATIC, SAFE: Eye level control
panel: centralized combustion controls;
modulated firing; electronic flame
safeguards.
FUEL CONTROL: Precise metering of
fuel via special metering cam.
AIR CONTROL: Unique rotary damper for
accurate metering of combustion air.
CLEAN FIRING: Accurate air-fuel ratios
throughout the modulating range. CB
designed air compressor, and efficient oil
or gas burner design.
PACKAGED: A complete unit from a
single source. Cleaver-Brooks designs.
builds, tests and ships to your job site
ready for quick hook-up. Starting service
assures peak on-the-job performance.
-------
STEAM BOILERS DIMENSIONS AND RATINGS
(15 LB. AND 150 LB. STEAM)
Rfl-ftF-RD
U^ =-*..
LENGTH
ELECTRICAL
SERVICE
CONNECTIONS
NOTE: DIMENSIONS MUST BE
CONFIRMED FOR CONSTRUCTION
W
83?" ........................... A...25--11"
"***" '••••••••••••••»• B 21 *• 3**
SjUiSTI? «*.••••• ..... ";;;;;;;;;;; c .'.'.' 2i'- 2"
Front Head Extension ...... n 99"
Rear Head Extension ............ ! ! " C " ' 27"
Front Ring Fig. to Nozzle (15& ISO Ib.).. f '.'.'. 128"
WIDTHS
Overall ............. I 118»
Base. Inside .........
c.m.r to outside Hinge....;;;;;;;;; G;;
HEIGHTS
MINIMUM CLEARANCES
Rear Door Swing oo «.. 5..
Front Door Swing ... EE «• n«>
Tube Remove). Rear " & " tg.",0,..
Tube Removal. Front i.^GG".' 18'- 4"
""NIMUM BOILER ROOM LENGTH
DOOR SWING AND TUBE RBMOVAL
Rear of Boiler •* en. ...
Front of Boiler i].'."; Up"' AA'ln"
Thru Window or Doorway \', | ;no' |; 34'-8"
WEIGHT IN POUNDS
Normal Water Capacity 27.790
Approx. Ship. Wgt. 15 Ib 82 000
Approx. Ship. Wgt. ISO Ib '.'.'. 53*600
Approx. Ship. Wgt. 200 Ib f* ™
Base to Steam Outlet".'.'.'.'.'.'.'.'.'.'.'.'.'.'f'" *v'iv'
Height of Base '. Q." ;; ig«
BOILER CONNECTIONS
Feedwater. Right end Left 8 ... 2H"
Auxiliary Connection 2... 114"
Low Pressure (IS Ib. only|
Steam Nozzle u 12"FLt
Drain. Front and Rear fl!;; 2"
High Pressure (ISO Ib. only)
Surface Biowofr, Top C T... 1"
Steam Nozzle ; Y ... 8"FL ft
Slowdown. Front and Rear W... 2"
Connections threaded unless
indicated - Fig. 1 - ISO Ib. ANSI
Fig. tt - 300 Ib. ANSI
VENT STACK
Diameter (flanged connection) 88... 24"
CAPACITY
Rated capacity in Ib*. etaam/hr. (212 F) 27 600
BTU output 1 1 000 BTU/hr.) ...... ..... 26 780
EDR steam gross ................... 11l!eOO
FUa CONSUMPTION
GasCFH
1000 ITU-natural ................. 33 BOO
Gas (therms per hr.|
Light Oil GPH
Heavy Oil GPH
POWER REQUIREMENTS
Blower motor ...................... 50 HP
Oil Pump - Light Oil ............... i HP
Oil Pump - Heavy Oil .............. * HP
Air Compressor (Oil Firing Only) ..... 7h HP
MINIMUM REGULATED GAS PRESSURE
Standard Train .............. . ...... 73" ivc
ltd Train (Former FIA) .............. 73" WC
FM Train ......... . ................ jy ^g
GUARANTEES AND TESTS
:FICIENCY - The CB 800 HP packaged boiler is goer-
d to operate et e minimum fueMo-steam efficiency of
-r greater over the ooereting renge.
OP TESTS - The packeged boiler shall receive factory
by the manufacturer to cheek construction
ion.
All tests may be witnessed by purchaser at his
own expense and upon sufficient notice.
3. STARTING SERVICE - After boiler installnion is com-
plated, e field representative will start the boiler and train
the operator. This service is not to exceed two consecutive
days. Any additional starting instruction or service required
by the purchaser or ultimate owner will be charged at pre-
vailing rates.
Extra service time requested by the purchaser or caused by
incomplete installation work or other factors not a pert of
the Company's responsibility will be charged to the pur.
chaser at prevailing rates for labor and expense.
-------
August 1990
APPENDIX K
UNITED KINGDOM CASE STUDIES
BEST PRACTICE PROGRAMME
New Practice —Final Profile
Protect Obfectiv*
To demonsirale (he feasibility energy saving and
commercial advantages ot using landlill-gas-
lueiied spark igmiion engines to generate
electricity in parallel with the national distribution
network
Potential UMTI
Remote or rural landfill sites witnoul easy access
to direct consumers ot landliii gas
Investment Cost
Stewartbv C418.500
Replicators £464.000
(1987 prices)
Savings Achieved
Stewartby C15B.OOO/year
Replicators C99 400 - C118 900
(1987 prices)
Payback Period
Slewartby: 24 years
Replicators 3.2-4.7 years
Project Summary
in this protect, three 275 kW spark ignition engines
fuelled by landfill gas were installed at a landfill site
ai Slewartby in Bedfordshire They are used to
generate over 66 million kWh/year ot electricity
the power generated being sold at peak periods to
the London Brick Company system and at other
times to Eastern Electricity. A small proportion of
the power was used m-house The protect was
prompted both by the incentive to harness the
energy in the environmentally controlled landfill
gas at the site and by the success ot early on-site
experiments with the use ot landfill gas for power
generation
Host Organisation
Shanks & McEwan (Southern) Ltd
Woodside House
Church Road
Woburn Sands
Milton Keynes
MK17 8TA
Monitoring Contractor
Ewbank Preece Ltd
Prudential House
North Street
Brighton
Sussex
BN1 1RZ
Tel No: 0273 724533
Telex No: 878102
Mr MR Homsby
Equipment Manufacturer
Dorman Diesels Lid
TixaliRoad
Stafford
ST16 3UB
Tel No: 0785 223141
Telex No: 31656
Fax No: 0785 215110
Mr OL Jones
Mr JJLusby
ELECTRICITY
GENERATION
USING
LANDFILL GAS
.> '
•»....» *•
•* . . ./. f
fc'firw Ktflrlrnr* Offlrr
Landfill gas power generation facility and abstraction plant
-------
Th« Stewartby Site
The Siewartby site of Shanks & McEwan
(Southern) Ltd (SMS) occupies a total o( 74 ha and
had an original void volume of 10 million m3. It
receives approximately 1.000 tonnes of waste per
day transported by rail trom London, together witrt
some local waste. Adjacent to the site is the
London Brick Company (LBC) Siewartby
brickworks which produced about 12 million
bncks/week in 1987
SMS s initial involvement m the development of
landfill gas extraction m 1979 led to gas from five
wells being used to tire bricks in a nearby LBC kiln
This was followed by an earty study of the
feasibility of electricity generation based on a
Rolls-Royce B81G 8-cytinder gas engine driving a
75 kVHV generator.
Deployment
The success of the initial electricity generation
trials lea to the installation of three Oorman type
12STCWG spark ignition engines coupled to
ail-cooed generators.
Bom vertical ana horizontal wells have been
installed to extract the landfill gas. and more are
planned for me tulure. Knock-out drums tor water
removal are located in each of the polyethylene
lines trom the landfill site, two on the longer
(500m) line ana one on each of the other lines The
gas is passed through pre-lilters pnor to
compression.
The compressor, a single, constant displacement
vane-type unit manufactured by Hammond
Engineering Ltd. is driven by a 45 kW electric
Control pan*
motor It is rated to supply 680 mVh against 1.3
bar g. The compressed gas passes through an
altercooler. baffle water separator, chiller and fine
litters before being supplied to the adjacent
engine house Any surplus gas is flared.
Each turbo-charged. 4-stroke. 12-cytinder.
Vee-torm engine unit s rated at 275 kW output at
1000 rpm when running on landfill gas Because of
(he lower calorific value of this fuel, the rating
quoted is some 11% below the engines normal
rating when operating on natural gas The units are
cooled by radiators mounted on me same
DM
framework as the engines, and the air used is
drawn trom outside the engine room Twin, paper
element air filters are provided tor each cylinder
bank, and each engine is fitted with a single
exhaust ducted horizontally to exit through the
engine-room wall.
The engines are directly coupled to Newage
Stamford air-cooled generators These are rated
at 350 kVKV and generate at 415 V The entire
generation plant is housed m a single-roomed
engine house which also contains control panels
and the lubricating oil tank. The units are designed
to operate unattended, so comprehensive
interlocks are provided to trip the units in the event
of low gas pressure, spit-back m the carburettor.
low oil pressure, high engine temperature or
engine overspeed. All engine trip circuits are
linked by telephone to a 24-nour call-out system
Electricity is supplied at 415 V tor m- house use and
a small proportion ot the power exported is
supplied at the same voltage to LBC The main
export power is. however stepped up to 6 6 kv via
a single transformer. During the daytime all this
power s taken by the LBC system LBC have a
peak power consumption of about 56 MVA during
the daytime when the brickworks are in operation
Overnight and at weekends however, their load
talts to a minimum of about 300 kW As landfill gas
cannot be stored economically, the generating
plant at SMS is operated continuously, and the
balance of power generated dunng periods ot tow
demand s exported 10 Eastern Electricity at 33 kV
Ptont Performance
The gas compressor has operated almost
continuously since February 1987 During that time
there has been a failure in me oil supply, requiring a
new electric oil pump, and three compressor
failures resulting from water getting through the
water separation systems. These laiiures required
compressor replacement or rebuild m each case
and action has been taken to prevent any
recurrence. Three subsequent failures {lor
different reasons) were also rectified and me
compressor has operated without maior problems
since the last quarter of 1988.
The generators nave run almost continuously
apart from mator service shutdowns and minor
faults Most ot the faults were etectncai and were
rectified by adiustments 10 equipment There nave
-------
been few problems with me use ol landfill gas as a
fuel, although low methane content has
occasionally caused the units to trip A typical
methane content in the gas during the early stages
ol monitoring was 50%. This has since increased
to 58% after rectification of air leakages in the gas
collection pipework.
The generation units have shown consistently
high service factors (94-95% for Units 1 and 3 and
93% for Unit 2V The engine service at 22.000
hours snowed the engines to be in generally good
condition with only minor problems of wear.
Annual Power Generation and Distribution
Based on operation to date and an annual capacity
factor of about 91.5%. annual power generation is
assessed at 6.612.705 kWh year.
This total comprises
• exports to LBC: 4.827.275 kWh/year (73%);
• exports to Eastern Elecuiaty; 925.779
kWh/year (14%);
• internal consumption: 859.652 kWh/year
(13%).
Approximately 23% ol internal consumption
(198.381 kWh/yeari is used in SMS s own offices
on site and represents a saving to SMS who no
longer have to import from Eastern Electricity
Income from Electricity Sales
Sales to LBC at a rate ol 2.93p/unu total
C!4l.439/year
Sales to Eastern Elecinoty at a rate of 2 36p/unii
total E21.BdB.yeai
The additional money available to SMS from
savings on imported electricity amounts to
£6.467/year giving a total income ol
£169.754/vear
A further loentitiabie saving derives from the tact
that if SMS did not have a power generation
protect tnev would sun need to Hare the landfill
gas This would involve a compressor and the
power to onve it wnicn m tms particular location
would cosi aooul C48 000/year
Allowing let operating ana maintenance costs ol
£59.800'year total net income and savings it the
Siewartby sue amount to £157954/year
The capital cost of the protect was £418.470 For
the purposes ot this analysis, the cost of the
compressor i £36.650) has been exciuoeo from
the total cost as this would be required anyway to
flare the gas Based on me resulting investment
cost of £381820 the simple payback is 24 years.
CM abstraction plant
Financial Benefits to Replicator*
Assuming that 90% of the units generated
(5.951.435 kWh/year) are exported at an average
tariff ol 2.75p/umt. the annual income would be
£163 664/yeai Additional savings made against
the hire and operation of a portable generator for
the compressor amount to £15.000/year in the
case of a replication site with a suitable power
supply Operating and maintenance costs remain
at £59.800/year. Net annual income is therefore
£l18.864/year. giving a payback period on a
£381.820 capital cost ol 3.2 years
For a replicator for whom gas control is not a
prerequisite, no allowance can be made against
the portable generator lor the compressor, ana an
additional figure of £4 500/ year must be added tor
operation and maintenance. This gives a net
Annual OO'.ve-
Generation mWh vean
Exports IkWh vean
internal consumption ikWh/vean
income from power sales
Operating ana maintenance costs
Savings on portable Generator tor
compressor
Net annual income
Capita! cost
Simp* payback
Stewartby
6612.705
5.753.053
859 652
£169754
£(59.800)
£48.000
C157.954
£381 MO
2.4 years
Replication
site without
gas system
6.612705
5.951 435
661.270
£163.664
£(59.800)
£15.000
C1 18.864
C381.B20
3.2 years
Replication
site with
gas system
6.612705
5.951 435
661.270
£163.664
£(64.300)
£99.364
C483.970
4.7 year*
annual income of £99.364/year SMS estimate
that, prior to the start of this protect £45.500 had
already been spent on the gas collection system
and associated wells it this figure and the cost of
the compressor is charged to me protect then the
capital cost 10 the replicator would be £463.970
giving a payback penoo ot 4.7 years
Combined Heat and Power Generation
Potential
The engines at Stewartby operate pureiv as power
generation units However, the potential does exist
for heat recovery from the plant ootn as steam
from waste heat boilers on the exhaust and as not
water from the cooling water circuits
Estimates trom Dor man indicate that at full load
and allowing for losses, about 110 kW could oe
recovered from each engines exhaust Using an
85% capacity factor the total heat energy available
from the three engines would amount to 8 850
GJ/year
A further 260 kW would be available from me
coding circuit equivalent to 20 900 GJ-vear Tne
recovery ol this low-grace neai iat annul 70"Ci
would depeno on an appropriate aemana oemg
available
The cost ot generating the 29.750 GJ m either gas
or gas oil-fired boilers operating at 75°0 efficiency
would be £2 50/GJ A combined heat and powei
generation system would therefore save a further
ClOO.OOO/yeai (£30.000/year it heat trom me
exhaust systems only was recovered) and would
reduce the payoack period to 1.5 years (20 years i
These figures make no allowance lor me capital
operating and maintenance costs of waste heat
boilers
-------
Comments Inxn Shanks 4 McEwan
Environmental landfill gas abstraction is the duty ot
every company disposing of wastes. The gas
which is collected must be used usefully or
deposed of to render it as harmless as possible.
Shanks & McEwan have been in the forefront of
the commeraal use of landfill gas. starling with
bnck kiln firing m 1981 and electricity generation m
1964.
The development of the landfill she at Stewartby
required the installation of equipment to flare large
quantities of landfill gas. There was no adequate
electrical supply available and. at first a
diesel-powered generator was used to produce
the etectncrty When larger quantities of etoctncrty
were required, the current protect became
financially feasible because of savings made by
substitution of the diesel generator as well as
income secured from the sale of etectncrty
This protect which generates 1.10OW using spark
ignition engines, is the second stage m the
company's strategy for the conversion of landfill
gas to electricity It has shown that a number of
engines can be operated w parallel and run
unattended tor 24 hours a day but sbli operate to a
high level of efficiency With over 100.000
operating hours achieved we are conftdeiH m
pressing forward with plans to generate electricity
at all company landfill sites which have commercial
quantities of landfill gas available.
Woodekte HOUM
Shanks* McEwen (Southern) Ltd
Shanks & McEwan (Southern) Ltd (formerly
London Bnck Landfill) operate a number of landfill
sites in former quarries of the London Bnck
Company. These sites cover a total area of some
1.300 ha with a nominal volume of 130 million m1.
The company has been closely involved in the
development of landfill gas extraction smce 1979
and has conducted a number of protects both with
the Department of Energy and the Department of
the Environment.
MrHDTMoss
nchrvcdl Director
Shanks & McEwan (Southern) Ltd.
The work described here was earned out under me Energy Efficiency Demonstration Scheme. The Energy Efficiency Office nas replaced the
Demonstration Scheme oy the Best Practice programme which is aimed at advancing mO disseminating impartial information to help improve energy
efficiency Results torn the Demonstration Scheme will continue to te promoted However, new protects can only be considered for support under the
Best Practice programme
More detailed information on the Shams A McEwan protect a contained ei the final report NP/19.
For cooies of reports and further Mormatton on tttfa or other Industrial piD^elK,pleaMeonlattEfwgyEfflcleneyEnqulrfMBurMu, Energy
lechr-ogy SupfMrt Unit (ETSU), BuHding 156, Hm^
(BRECSU),
tnformirtKvi iw !•>»** "••'-
s, p«eea«coTrtact
t Garaton, Watford WD2 7JR. Tel No: 0923 664258
-------
Energy Efficiency Office
DEPARTMENT OF ENERGY
Energy Efficiency Enauines Bureau
Energy Tecnnology Suooort Unit lETSU)
Building 156 Harwell Laboratory. Didcot. Oxon 0X11 ORA
Tel NO: 0235 436747 Telex No: 83135 Fax NO: 0235 432923
FEBRUARY 1991
Energy Efficiency Demonstration Scheme Electricity From Landfill Gas
Expanded Project Profile 249 using Gas Turbines
A demonstration of the use of gas turbines to generate power In the waste disposal Industry
Potential users
Medium-large scale landfill waste disposal operations.
Investment cost
C1.946.00011986 crices!
Payback period
11 years.
Savings achieved
57.795 GJ per year valued at £176.780 per year
Host company
BFI Packington Ltd
Packington Hall
Packington Park
Menden
Coventry
CV77HF
Tel No: 0676 22155
Monitoring contractor
Ewbank Preece Ltd
Prudential House
North Street
Brighton
BN11RZ
Tel No: 0273 724533
Mr M Hornsoy
Equipment suppliers
(Gas turbine generator set)
Centrax Ltd
Gas Turbine Division
Shaldon Road
Newton Abbott
Devon
TQ124SQ
Tel No: 0626 52251 Telex No: 42935
MrARStallard
(Compressors)
Belliss and Morcom
ickmeid Square
Birmingham
B161QL
Tel No: 021 454 3531 Telex No: 337507
Mr B Lamb
The aim of the project
Most of Bntam's waste is disposed of in landfill operations. As
the organic waste contained in a landfill site decomposes.
landfill gas. mainly a mixture of methane and carbon dioxide, is
produced. This gas is noxious, inflammable and can be
explosive, and it is recommended that the gas is collected and
burnt. The aim of the protect was to demonstrate the
commercial viability ol burning landfill gas in a gas turbine, which
could be used to generate electricity The protect also
investigated the requirements to pre-treat the gas prior to
combustion in the gas turbine and the extent of any
environmental impact from such a proiect
Centrax turbine
-------
How energy was saved
Approximately one million tonnes of waste from Birmingham
and Solihull is disposed of ever/ year in the Little Packington
landfill site, midway between Birmingham and Coventry. The
landfill site is 380 acres m area, and by 1987 contained about six
million tonnes of controlled waste. Landfill gas seepage was a
nuisance anc as initial boreholes produced gas with a methane
content of 60%. it was decided to install a 3.65 MW gas turbine
to generate electricity for direct export to the Midland Electncity
Board (MEB). The project was supported under the Energy
Efficiency Demonstration Scheme.
Landfill gas is supplied to the generation plant compound via
1.500 metres of buned pipe. The gas is scrubbed and passes
through a centrifugal blower before being compressed in two
Bellas and Morcom WH56N compressors. Each compressor is
rated at 55% duty, although each is capable of delivering 70% of
the total gas requirement when operated with the blower.
Before delivery to the turbine, the gas is cooled and superheated
to control condensation of hydrocarbons. The 3.65 MW
generator set is a Centrax model CX 350 KB5 powered by a
General Motors Allison 501 KB5 single-shaft gas turbine which
runs at 14.250 rpm. The drive to the Brush 6.125 MVA generator
is taken through a step-down gearbox to 1.500 rpm. The
generator output is exported to the MEB at 11 kV via a 1.8 km
long underground cable.
The turbine first ran on landfill gas on 23rd September 1987.
Dunng the plant acceptance trials the automatic condensate
return valves were not functioning. The valves were removed
and cleaned and. after reinstallation. functioned correctly. During
commissioning, the No 2 compressor failed and the
replacement unit also failed. With this compressor out of
service, most of the operation during the period to January 1988
was undertaken using No 1 compressor supplemented by the
gas blower. Under these conditions, it was possible to raise the
turbine output to about 2.7 MW.
During early running of the compressor, the cylinder head and
valves suffered fouling by chlonde salts and hydrocarbons. In
late December 1987 heavy corrosion was noticed in the
stainless steel flexibles connecting to the compressor. The
fouling and the corrosion were traced to the scrubber liquor
which was being dosed with sodium hypochtonte and sodium
hydroxide. The dosing was thought necessary to remove any
hydrogen sulphide present m the landfill gas. Unfortunately, it is
likely that the sodium hypochtonte also reacted with
hydrocarbons to produce hydrogen chloride. Following advice
from the manufacturers, dosing with sodium hypochlome was
stopped.
In November 1987, to prevent belling which had been reported
on similar plant in the USA. replacement ends of the turbine fuel
manifold were manufactured. Three senous failures occurred on
the gas turbine, all involving the fracture of one of the gas
injection nozzles. All six nozzles were replaced in October 1988
and a further redesign is in hand. Spurious tnps of the turbine
occurred towards the end of 1987 and into earty 1988 which
were mainly caused by the scrubber control panel, which has
since been replaced.
As a consequence of these initial problems the system operated
with an availability of 85% and at a reduced average output of
58%. However, since earty 1988 the system has proved reliable
and has achieved near continuous running. In the period June
1989 - May 1990 the system has been running with an
availability of 95% while operating at 79% of rated output.
All the monitored exhaust emissions have been tower than the
limits allowed for municipal waste incinerators, except in one
instance when the HCI level emitted would have marginally
failed to comply with the EC limit allowed. The noise level
measurements taken at the site have indicated that, at a
distance of 50 m. the noise was inaudible above the total
background noise, even at night.
Switchgear Room
1 Transformer
2 MEB metering panels
3 Mains circuit breaker
4 Auxiliary C/BfTran)
5 Generator OB (Gen)
6 Generator IIC/B (Future!
7 MEB tnp circuit power supply
8 Switchgear (48V) power supply
9 Batteries (24V)
10 Battery charger panel (24V)
11 Turbine control panel
12 Generator control panel
13 Gas compressor pane)
14 Motor control centre
IS Neutral earthing transformer and contactor
16 Demountable engme removal beam
17 Air compressor
18 Gas receiver
19 Gas compressor
20 High pressure natural gas bottles (for starting only)
21 Gas scrubber
22 Scrubber dosing tanks
23 Cooler-gas compressor
24 Booster
25 CX350KB5 generator set
26 Turbine exhaust system
27 Turbine air mtake system
28 Oil cooler vent system
29 Alternator vent system
30 Turbine enclosure vent system
31 Generator room vent system
32 Compressor room vent system
33 Main cables terminal box
34 Neutral cable terminal box
35 Scrubber control panel
36 Haion bottles
Gas turbine plant layout
-------
Energy and cost savings
The total capital cost of the protect at October 1986 pnces was
£1.946.000. In addition to this amount, expenditure was
required for the installation of the gas collection system. Since
this expenditure was necessary to control the gas hazard, the
cost of these items has not been considered for this particular
protect. On replica sites, a gas collection system may be
installed solely for the purpose of collecting gas for the
generation of electricity Therefore, in the following analysis two
alternative cases have been considered: one with the additional
figure of £300.000 has been allowed to cover the cost of
collection equipment.
If the proiect had not been undertaken, costs of £55.500
involved in controlling the landfill gas would still have been
incurred This is displaced expenditure and may be considered
as income for the Packmgton site. Considenng these points, the
table compares the economics of the Packmgton site with a
replica site without a gas collection system
The figures in the table are based on the measurements taken
curing tne monitoring period October 1987 - May 1989 which
includes the early operation of the plant when availability was
relatively low. From June 1989 to May 1990 a further 8.760
hours of operation were completed at improved efficiencies If
the plant had achieved target generation with the original
electricity tanff. this payback would be reduced to 4.5 years
Centrax has since sold another unit to operate solely on landfill
gas. This installation enioys a Comprehensive Maintenance
Contract with guaranteed availability. The cost of the contract is
significantly less than the O&M figures quoted in this profile
The use of landfill gas as a fuel to generate electricity is of
considerable benefit to the nation Not only does it contribute to
the security and diversity of supply within the Non-Fossil Fuel
Obligation, but also helps towards environmental control of
landfill sues
Gas scrubber
Paeklngton
Replica site
wttti no gas
collection
system
Income from electricity sales
Displaced expenditure
0 & M costs
Net annual income
Capital costs
Simple payback
380.280
55.500
(259.000)
176.780
1.946.000
11.0 years
380.280
(259.000)
121.280
2.246.000
18.5 years
-------
BFI Packlngton Ltd
BFI Packingion Ltd is an American-owned company operating a
landfill site at Little Packingion. between Birmingham and
Coventry on part of the estate of the Earl of Aylesford.
Comments from BFI Packlngton Ltd
The primary objective of this protect was 10 control the potential
hazard of landfill gas. Initial investigations were carried out on
site to determine the extent to which landfill gas was being
produced. This investigation proved that there would be
substantial volumes of gas to handle. It was decided at this
stage that there would be sufficient gas to support the operation
of a gas turbine. The company's preference lay with a gas
turbine due to the good combustion that a gas turbine produces
and hence low exhaust emission levels.
The initial operation of the generating station proved
troublesome. These teething problems resulted in relatively low
plant availability during the early days. Once these problems
were resolved, the plant managed to give a high level of
availability The plant is now capable ot giving 97% availability
and is burning 2.5 million cubic feet of gas per day This high
availability coupled with benefits under the Non-Fossil Fuel
Obligation have served to improve the economic results of the
protect The economics are now more favourable than original
estimates.
At the end of the day. this project has proved to be a resounding
success and we are all very pleased with what has been
achieved.
Mr T Uncles
Consultant Gas Engineer to
BFI Packlngton Limited
Further Information
The work oescnbeo here was earned out under the Energy
Efficiency Demonstration Scheme More detailed information
on this croiect is contained in the final report ED/296/249 The
Energy Efficiency Office has replaced the Demonstration
Scheme oy tne Best Practice programme wnich is aimed at
advancing and disseminating impartial information to help
improve energy efficiency. Results from the Demonstration
Scheme will continue to be promoted However, new projects
can only be considered for support under tne Best Practice
programme
For copies of reports and further information on this or other
protects, oiease contact tne Energy Efficiency Enquiries Bureaux
aienntr
Energy Technology Support Unit (ETSU)
Building 156
Harwell Laboratory. Oxon 0X11 ORA
Tel No 0235 436747 Telex No 83135
Fax No 0235432923
or the
Building Research Energy Conservation Support Unit (BRECSU)
Building Research Establishment
Garston. Watford WD2 7JR
Tel No 0923 664256 Telex No 923220
Fax: 0923 664097
information on participation in the Best Practice programme ano
on energy efficiency generally is also availaoie from your
Regional Energy Efficiency Office
-------
Energy Efficiency Office
For furttier information contact
Energy Efficiency Enauines Bureau
Energy Technology SuDDOrt unit (ETSU)
DEPARTMENT OF ENERGY Building 1S6. Harwell Laboratory. Diacot. Oxon 0X11ORA
cfwcnwt
JANUARY 1988
Energy Efficiency Demonstration Scheme
Expanded Project Profile 217
The use of Landfill Gas as a
Replacement Fuel in a Shell
Boiler
A demonstration of reduced conventional fuel consumption In the food Industry
Potential users
Shell boiler operators within a 10 km radius of a landfill site
investment cost
C140.743 (including boiler replacement)
£50.000 aoproximaiely (burner replacement only)
Payback period
3.0-6.6 years (including trailer replacement)
1 1-2.3 years (burner replacement only)
(both dependent on the fuel discount rate)
Savings achieved
C21.464-C47.170/year (dependent on the fuel discount rate)
(1986 prices)
Host company
Premier Brands UK Ltd
Pasture Road
Moreton
Wirrall
Merseyside L46 8SE
The aim of the project
In this demonstration, landfill gas produced at a landfill site on
the outskirts of Birkenhead was piped some 2 75 km to a
Premier Brands factory producing biscuits and other food
products The gas was used in conjunction with natural gas and
heavy fuel oil to fire a new shell boiler to provide steam for
central heating and process use. The aims were to show that
unrefined landfill gas could be used to fire a shell boiler, to
determine whether it would increase the nsk of chemical
corrosion and to assess the environmental acceptability of flue
gas emissions. The consumer benefited financially from the
lower pnce of landfill gas compared with natural gas.
Monitoring contractor
NIFES
NIFES House
Smderiand Road
Broadheath
Altnncham
Cheshire WA145HQ
Tel No: 061 928 5791
Telex No: 669069
Mr G Davies
Equipment manufacturers
BURNERS
Hamworthy Engineering Ltd
Combustion Division
Fleets Comer
Poole
Dorset BH17 TLA
Tel No: 0202 675123
Telex No: 41226
MrAGParrott
BOILER
Wallsend Boilers Ltd
PO Box 38
CalderValeRd
Wakefield
West Yorkshire WF15PF
Tel No: 0924 378211
Telex No 55368
Mr A E Chadwick
Installation contractor
Bayliss Kenton installations Ltd
Harwood Street
Blackburn
Lancashire BB130W
Tel No: 0254 60011
Landfill gas shell boiler
Landfill g«» firing the boiler
-------
How landfill oas reduced conventional fuel
consumption at Premier Brands
Premier Brands UK Ltd manufactures biscuits and other food
products at Its factory in Moreton. Merseyside. Steam is raised
in a central boiler plant for space heating and process use. The
base steam load is in excess of 1.250.000 therms/year.
Originally, the central boiler plant consisted of two duel-fuelled
'Maxecon' single furnace boilers rated at 18,000 and 30,000
to/hour, a disused 8.000 to/hour Towler water-tube boiler and a
40.000 Ib/hour water-tube boiler which had recently suffered
from superheater tube failure. The serviceable boilers are now
retained as stand-by capacity.
Bidston Methane Ltd (BM) was formed to exploit the
commercial potential of landfill gas extracted from a major
waste disposal site. In 1984. Premier Brands (then Cadbury
Typhoo Ltd) was approached by BM regarding the possibility of
using landfill gas from a site some 2.75 km away. A survey of
companies within an 8 km radius of the waste disposal site had
identified Premier Brands as a suitable potential customer. A gas
sale agreement was signed earry in 1985.
A multi-fired Maxecon unit rated at 30.000 Ib/hour with a
working pressure of 150 psig was installed on the site of the
previously scrapped water-tube boiler plant. The new unit was
capable of f mng on unrefined landfill gas and was fitted with
fire-tubes and twin burners. Because this was the first scheme in
the UK to fire unrefined landfill gas in a shell-type boiler, the
protect was supported by a grant from the Energy Efficiency
Office's Energy Efficiency Demonstration Scheme (EEDS). As
pan of this support the National Industrial Fuel Efficiency
Service (NIFES) was contracted to monitor the contract. The
landfill gas extraction project also received support under the
Scheme and this is described in a separate Expanded Project
Profile (216).
The new boiler was a conventional thre»pass wetback
economic unit as normally supplied for natural gas or fuel oil
firirxj. Each furnace tube was fined with a Hamworthy multi-fuel
burner designed to bum heavy fuel oi. natural gas or landfill gas.
In addition, the burners were capable of firing landfill and natural
gas simultaneously. The Maxecon boiler was considered to be
particularly well-suited to the project as the reversal chamber
design enabled the user to operate on one furnace for indefinite
penods.
The boiler was arranged so that, during periods of tow steam
demand, the unit fired landfill gas on one fratube. The second
burner was either off or was used as a 'top up' using natural gas.
The two gases were fed into a gas train consisting of an
upstream manual isolating varve fitted with a rrucroswitch. two
Clan 1 automatic shut-off varves, j butwrfly control waive and a
dowrwreamffujfHjaJisofcrtingvalvtfrnedtotfwgasinarMfold
Mat flange. High and low gas pressure switches were fitted
wrma third pressure switch fortnevarva proving system.
Monitoring of the project during the first year of operation
showed that the shell boiler could be fired successfully with
landfill gas. One difficulty encountered was with first-time
ignition of landfill gas which was not always successful. On
some occasions, it was necessary to intervene manually.
Subsequent to the monitoring period this has been rectified
An oxygen-trim system was installed to overcome the problems
associated with variations in the calorific value of the landfill gas
and hence the excess air levels. The input of landfill gas was
established at 33.000 fH/hour as a more consistent calorific
value could be maintained at this rate. Excess air levels could
then be set more accurately and any slight deviations could be
handled by the oxygen-trim system.
During the first year of operation, plant stoppages were minimal
and the overall availability of the gas was 98%. Over 60% of the
consumer's natural gas consumption was replaced by landfill
gas. The average thermal efficiency of the boiler plant fired with
landfill gas was 77.1 % compared with 78.4% for natural gas
firing. The quality of the landfill gas was consistent and no
noxious emissions were detected in the flue gases. There was
no evidence of intensified boiler fireside corrosion during the
monitoring period and fouling was not a problem.
Boiler replacement, which was one of the major expenditures
for this project, is unlikely to be considered necessary in the
majority of future applications of landfill gas. A typical site will
only require burner replacement. Landfill gas therefore can
provide an even more cost-effective option, with an associated
reduced payback penod of less than three years.
Atomising Cup
»bur
ft*'e*«
Davis Road
School \
260 mm O.D. Polyethylene
LandfiN Gas Main
Bidston Trading
Estate
v Bidston Moss
Landfill Site
Plant ftSwitchroom
River Birket Crosimq
Route of the tandHII ga» mafti
-------
Conventional fuel and cost savings
During the 12-month monitoring period. 1.048.282 therms were
supplied by landfill gas. 460.120 by natural gas and 205.312 by
fuel oil. Theprice of natural gas fell during the period which in
turn affected the pnce of the landfill gas. Fuel costs for the year
were: natural gas £121.615; fuel oil £45.867. The accompanying
table shows the cost of landfill gas tor 10%. 15% and 20%
discount rates (per therm).
To determine the financial savings made as a result of changing
to landfill gas. it is necessary to take acount of the difference in
the thermal efficiency of the boiler for natural and landfill gas and
to calculate how much natural gas would have been required to
give the same thermal output achieved with landfill gas firing.
The landfill gas consumption of 1.048,282 therms was adjusted
to give an equivalent natural gas input of 1.030.900 therms
(4.124 tee) costing £252.811. Annual fuel cost savings for 10%.
15% and 20% discounts of landfill gas over the equivalent
natural gas requirement are £21.464. £34.317 and £47,170
giving simple payback periods of 6.6.4.1 and 3.0 years for the
capital cost investment of £140.743.
A potential landfill gas user with a suitable existing boiler would
only need to install a triple fuel burner and ancillary equipment
which would probably cost about £50.000. Assuming the same
levels of saving apply this results in payback periods of 2.3.1.5
and 1.1 years respectively.
Replication
In the UK. approximately 25 M tonnes of biodegradable waste
is deposited each year throughout 669 landfill sites. Of these
approximately 300-350 contain sufficient quantities of refuse to
produce commercial quantities of landfill gas. In the main.
potential customers will be those large energy consumers
within a reasonable distance of a suitable landfill site (say 10 km)
and who have a continuous non-fluctuating base energy load in
excess of or dose to the anticipated site yield. However, this
does not preclude the smaller, non-continuous energy user
being able to make full use of landfill gas facilities. A landfill site
is not restricted to a single user and there is no fundamental
reason why it could not be used by a consortium. The application
of landfill gas would be ideal for the chemicals, paper, textiles
and food industries.
Multi-boiler plants and/or multi-burner boilers of the water-tube
or fire-tube type would be most suited to burning landfill gas in
commercial quantities. Most replicators would only require new
burners for existing boilers and this would improve the
economics of such schemes and reduce considerably the
simple payback penod.
Cost savings from using landfill gas
Landfill gas discount
10% 15% 20%
Landfill gas £231.347 £218.494 £205.641
Natural gas used instead £252.811 £252.811 £252.811
of landfill gas*
Savings £ 21.464 £ 34.317 £ 47.170
Payback penod 6.6 years 4.1 years 3.0 years
(including boiler replacement)
Payback penod 2.3 years 1.5 years 1.1 years
(burner replacement only)
•corrected for boiler efficiency when firing landfill gas
6_
•s
S t.
§. 5-
1 4
g 4-
u
5 3-
to
a
a>
f5
2-
.
X
X
Costs ai >
beginning of 1986
•*•»*,
Costsat*'
beginning of
X
X
N.
— • ^
*-
1986^
Co
«
«
Co
-— -.
—• —
sts for
•^
^-
stsfor
•* ~.
•*• —
986
.^
1986
— —
1=9
•• -
m^mm.
~~
"— •
• .
••w
» ^
•--
^
1 New boiler
J installations
_ Original boiler
J with new
burners)
0 10 15 20
Landfill gas discount on mterruptibte natural gas costs (%)
Simple payback periods for landfill gaa installations
-------
Premier Brands UK Ltd
Premier Brands is a maior UK manufacturer of biscuits and food
products. It is therefore a large consumer of energy. The
Merseyside factory at Moreton raises steam in a central boiler
plant to provide space and process heating. The factory base
steam load is in excess of 1.25 million therms/year.
Premier Brands' experience
During the early 1980s, site management faced a number of
difficult decisions regarding steam generation. The demand for
process steam had dropped dramatically as both confectionary
manufacture and corrugated paper making had ceased on site.
At the same time the generator and boilers were neanng the
end of their useful lives. During this period the site operated on
mterruptible gas with heavy fuel oil as stand-by. The first
attempt to reduce fuel costs involved the installation of a waste
fired boiler to be fuelled by combustible waste generated on
site. The proiect was unsuccessful and expensive. As a result.
the Company was hesitant when approached by National
Smokeless Fuels (NSF) with an outline proposal for the use of
landfill gas from the nearby Bidston landfill site However, it did
offer the opportunity to complete the renewal of the boilers.
Price relativities between landfill gas. interruptible gas and heavy
fuel oil were carefully monitored as the oil once varied. As a
result, it can be seen that the reduction in fuel costs assumed
for this protect have, in fact materialised. Landfill gas provides a
considerable proportion of our total fuel requirement The
technical risks thought to be associated with combustion and
corrosion were imagined, rather than real. Unfortunately the
installation does not allow for every permutation of landfill gas.
interruptible gas and heavy fuel oil and there continues to be
some difficulties experienced balancing landfill gas volume
against calorific value.
Close cooperation with all panics concerned and the setting of
tight deadlines for implementation have assisted with the
prefect's overall success. The protect has proved the
acceptibility of landfill gas as a replacement fuel in shell boilers
and achieved the cost reductions sought by the Company
Commitment to the protect is enthusiastic and it has been the
Company s most effective innovation in utilities.
Bob Mottram
(Site Director)
Further information
Tne worn aescrioea nere was carries out under the Energy
Efficiency Demonstration Scheme
Tne Energy Efficiency Office has replaced the Demonstration
Scneme by tne Best Practice programme which is aimed at
advancing and disseminating impartial information to help
improve energy efficiency. Results from the Demonstration
Scheme will continue to be promoted However, new protects
can only be considered lor support under the Best Practice
programme
More detailed information on this protect is contained in tne final
reoortED'19V217
For copies ot reports and further information on this or otner
protects please contact the
Energy Efficiency Enquiries Bureau
Energy Technology Support Unit (ETSU)
Building 156
Harwell Laboratory
Oxon OX11 ORA
Tel No 0235436747
Telex No 83135
Fax No 0235432923
Information on participation m the Best Practice programme ana
on energy efficiency generally is also available from your
Regional Energy Efficiency Office
-------
Energy Efficiency Office
^^ ^ Energy Technology SuDDort unit (ETSU>
DCOADTKMFNT Of F N E P G Y Building 156. Harwell LaDoratory. Didcot. Oxon 0X110RA
EP ART MB I* 1 Or c Te| No ^235 456747 Te(ex N0:83135 Fax No 0255 4J2925
DECEMBER 1986
Energy Efficiency Demonstration scheme
Expanded Project Profile 153
Landfill Gas used
as a Fuel In a
water Tube Boiler
A demonstration of conventional fuel savings In the paper board Industry.
Potential users
Operators of water-tube boilers within 1 0km of appropriate
landfill sites
Investm
C267.000
Payback period
Between 1 and 2 years
Savings achieved
C160.75Q/vr assuming a natural gas cost of 2Bp/therm and a
landfill gas supply discount rate of 15%
Host company
Purlieet Board Mills
London Road
Purfleet
Essex RM161RD
The aim of the project
Every year about 25 million tonnes of waste are buned in
landfill sites in the UK. Organic material in the waste disposed
of in this way decomposes under anaerobic* conditions and
often produces a methane-nch gas. This gas can give nse to
local environmental problems at some sites where the gas
must be collected and flared. In some cases, the amount of
gas produced is sufficient to be attractive commercially as an
alternative fuel to nearby industry.
In this demonstration, landfill gas produced at a large landfill
site at Aveley in Essex was piped to Purfleet Board Mills and
used as the base fuel on a steam-raising boiler. The aim was to
show that the gas could be used successfully in conjunction
with either natural gas or heavy fuel oil and that it would be a
safe and reliable source of energy The consumer benefited
from the lower pnce of landfill gas compared with natural gas.
It was anticipated that landfill gas would contribute about
5.000.000 therms (20.000 tee) to the 14.000.000 therms
(56.000 tee) consumed by the plant annually.
•in the absence of oxygen.
MonltorlnQ conti jctur
NIFES Consulting Engineers
Chamngtons House North
The Causeway. Bishops Stortford
Herts CM232ER
Tel No: 0279 58412
Mr A E Wright
Equipment manufacturer/Installer
COMPUTER. CONTROLS AND COMMISSIONING
Babcock Bristol Ltd
218PuneyWav
Crovdon
Surrey
Tel No: 01-686 0400
MrJTBoswell
BURNERS AND BURNER MANAGEMENT
Babcock Power Ltd
Combustion Equipment Department
165 Great Dover Street
London SE14YB
Tel No: 01-407 8383
Mr D L McLachtan
I 3 see Potential users
-------
How landfill gas reduced conventional
fuel consumption at Purfleet Board Mills
The waste disposal site at Aveley in Essex covers 66 acres
and receives large quantities of domestic refuse each year.
In 1979 the Greater London Council (GLC). who owned the
site, called in National Smokeless Fuels Ltd (NSR to
investigate the release of gas and to make recommendations
for its treatment. It was determined that decaying refuse
was generating a methane-rich gas in commercial
quantities which could be useful as a fuel to local industry.
One of the large fuel users in the area. Purfleet Board Mills.
agreed to buy landfill gas from Aveley and to use it to augment
the conventional fuels used on a Babcock water tube boiler at
its paper board mill The boiler, which was rated at 200.000
Ib/hour and fired by four natura^gas burners (with heavy fuel oil
as standby), raised steam for electricity generation Purfleet
Board Mills decided to change to landfill gas burning on one of
the burners. This involved installing a new 500m-long gas main
from the Purileet Board Mills boundary to the boiler plant.
replacing one of the old burners by a new burner designed
especially to bum landfill gas. and installing a computer control
system to optimise combustion conditions and control general
plant performance All these changes were maoe as part of
the Energy Efficiency Office's Energy Efficiency
Demonstration Scheme The laying of an underground pipeline
from Aveley to Purfleet - a distance of some 2Vz miles - was
undertaken jointly by the GLC and NSF.
Special consideration had to be given to the nature of landfill
gas in making the modifications. For example, the gas has a
higher moisture content and is a mixture of methane and
other, mainly inert, gases. It also has a lower calorific value
than natural gas and this value tends to vary with the rate of
use and the prevailing weather conditions at the landfill site.
The cross-sectional area of the gas main was made twice as
large to allow an increased rate of flow and so compensate
for the lower calorific value of the gas: the discharge area of
the holes in the burner were increased for the same reason.
At the Aveley site, the gas was chilled pnor to transport to
remove the mapnty of the water while, at the consumer
end of the pipeline, water traps and fine mesh filters were
incorporated to reduce still further the water content and
any entrained debns. The landfill gas was used as the base
fuel on the boiler so that the other conventionally fuelled
burners could compensate for any variations in supply. An
automatic computer control system regulated fuel and air
supplies to the three original burners according to steam
demand
The plant has now been operating in its new mode since
April 1983 and the performance has been sufficiently
encouraging for Purfleet Board Mitts to modify another
burner entirely at their own expense. Detailed monitoring
was earned out as pan of the demonstration from May 1983
to Apnl 1984. This recorded the consumption of all fuels
used, the thermal efficiency of the boiler and the calonf ic
value of the landfill gas. In addition, tests were made to
check whether corrosion within the boiler was increased by
using trie new fuel.
Results indicate that landfill gas has reduced the use of
conventional fuels by slightly less than was expected.
mainly because of a limited production rate at the well.
Improvements have now been made which should increase
the amount of gas available from the site and more than
match the original requirements. Filters have had to be
cleaned about every two months to remove a deposit of
sludge and occasionally the gas supply has been shut down
by the supplier for about an hour to allow maintenance to be
earned out. This process usually results in a higher calorific
value on return of supply. Regular checks on the calorific
value of the gas have revealed that it tends to be above
average after a holiday shut-down and below average
dunng periods without any appreciable rainfall.
Burning landfill gas has presented few problems at the
burner or in the boiler. By making it the base fuel, variations
in supply and the occasional shut-down have been
accommodated without any trouble. Initially, there was a
problem of flame instability with the new burner which was
caused by the gas discharge velocity being too high:
because of the high men content (CO}), landfill gas has a
much lower flame speed than natural gas. The holes in the
burner were opened up further to give a lower velocity and
no more problems have been expenenced. The general
appearance, shape and colour of the landfill gas flame is
virtually identical to that produced by a natural gas burner
Tests have shown that there has been no increase in the
incidence of corrosion in the boiler with landfill gas burning
Landfill
Gas
PT eline
Filters
Water Traps
J.
Forced
Draught Fan
High Pressure
Steam
J
From Aveley
(2'/j mnes)
-*-D-e
Purfleet Board Mills
C___—-j
rorceo
Draught Fan
-------
Conventional fuel and cost savings
Details of the consumption of fuels in the water tube boiler
before and after modification are given in the accompanying
table. Data for 1982 are taken from records kept by Purftoet
Board Mills and refer to the period 1 January-31 December.
while the 1983-84 figures come from the demonstration
monitoring exercise between May and April. As can be
seen, the average measured efficiency of the boiler
dropped between these two periods. If the boiler had
operated at its original efficiency throughout and the thermal
output for 1983-84 had remained unchanged, the total
thermal input for the period would have been 14.137.974
therms. Subtracting the contributions of natural gas and oil
from this figure gives the consumption of landfill gas as
3.827.184 therms (15.310 tee) corrected for the difference in
boiler efficiency.
The installation at Purfleet Board Mills cost a total of £267.000.
Financial savings in this demonstration resulted from the
lower price paid for landfill gas compared with natural gas.
Assuming that natural gas costs 28p/therm and that landfill
gas is supplied at a 15% discount, financial savings of nearly
£160.750 are made each year in an installation like this
giving a simple payback period of just over one and a half
years. The graph shows how the payback penod is affected
by different discount rates.
THERMAL INPUT:
Natural gas. therms
Fuel oil. therms
Landfill gas. therms
Total, therms
BOILER EFFICIENCY
THERMAL OUTPUT.
therms
.Before
modification
1982
12.943.703
691,346
13.635.049
79.5%
10.844.185
After
modification
1983-84
10.217.227
93.563
4.099.251 •
3.827.184"
14.41 0.041 •
14.137.974"
78%
11 244170
•Recorded data
••Calculated at 79.5% efficiency
30-
25-
15-
10-
5-
10.99 years
1.25 years
1.66 years
12.49 years
Simple Payback Period. Years
-------
Purfleet Board Mills' experience
E Charles Smith
Chief Engineer
"In 1980/81, Purfleet Board Mills had been conducting a senes
of investigations into alternative energy sources: during these
we learned from NSF -with whom we had previous
assoaaton-of the possibility of a supply of LF Gas suitable
for use as a fuel from a landfill site near the Purfleet Mill.
Energy was becoming a major proportion of production
costs, and had doubled in recent years. This possibility of
using LF Gas as a boiler fuel was examined in some detail
and its feasibility was confirmed.
There was in service at Purfleet a water-tube boiler with
spare capacity which could be converted, and in 1982
authority was given to proceed with the project.
It was anticipated that flame stability could be a problem.
and a low pressure burner was obtained to fit in place of one
of the four existing burners so that the boiler could be dual
fuel fired. Rue gas analysis and computer control was
installed to provide precise regulation and maintain
eff iaency. although some loss of eff iciency was anticipated
due to the higher non-combustible content of LF Gas.
Problems with the installation were few, and first f inng of
LF Gas took place in Apnl '83, one year after the proiect
started.
LF Gas provides some 30% of total fuel requirements, the
improved boiler control has compensated for losses due to
LF Gas and there has been no appreciable loss of operating
efficiency.
It was anticipated that some boiler gas-side corrosion
could occur due to LF Gas. but monitoring tests have shown
no measurable effect dunng the first year of operation
There were initially a number of boiler shutdowns due to
combustion disturbances; these were of short
duration and had been anticipated and allowed for in the
protect assessment. The protect is providing the anticipated
return with 4M therms being supplied in the first year of
operation.
The target of 5M therms was not achieved, but
arrangements have been made to extend the use of LF Gas
by converting a second burner.
The proiect has been successful It would have been more
convenient if this had been developed as part of a complete
new installation, or used in a separate base load boiler, since
the present installation seriously restricts any controlled
trials to determine optimum conditions. There is every
indication that this project will be developed and continue to
make a major contribution to energy cost reduction!'
Furttier Information
The work described nere was carried out under the Energy
Efficiency Demonstration Scheme.
The Energy Efficiency Office has replaced the Demonstration
Scheme by the Best Practice programme which is aimed at
advancing and disseminating impartial information to help
improve energy efficiency. Results from the Demonstration
Scheme will continue to be promoted. However, new protects
can only be considered tor support under the Best Practice
programme
More detailed information on this protect is contained in the final
report ED/060/153
For copies of reports and further information on this or other
protects, please contact the
Energy Efficiency Enquiries Bureau
Energy Technology Support Unit (ETSU)
Building 156
Harwell Laboratory
Oxon 0X11 ORA
Tel No: 0235 436747
Telex No: 83135
Fax No: 0235 432923
Information on participation in the Best Practice programme and
on energy efficiency generally is also available from your
Regional Energy Efficiency Office
-------
APPENDIX L
The Econonlcs of Landfill Gas Projects
in the United States1
By G.R. Jansen, Vice President, Laidlav Gas Recovery Systems
This paper is based on the experience of Laidlav Gas Recovery Systems in
developing, owning and operating landfill gas projects since the early
1980's.
Although GRS is currently operating 12 landfill gas projects, only one
of these, is a medium BTU project. This project is located in
Sacramento, California and sends over 1 M4 cubic ft./day to a Biomass
plant burning almond shells. The rest of the GRS projects are landfill
gas to electrical energy projects ranging in size from 650 Jew to 20,000
kw. The projects are located mostly in Northern and Southern
California.
The information in this paper including the capital costs, pricing of
electrical energy, and operating costs comes from the GRS electrical
projects. Although the overall economic analysis contained in this
paper is for a small electrical generating project, much of the same
type of analysis and evaluation of the same factors would have to be
carried out for a medium or a high BTU landfill gas project.
Medium BTU
The GRS Sacramento plant is a medium BTU project which began operation
in 1991 at a level of a little over 1.0 million cubic feet of landfill
gas per day. The landfill at Sacramento has continued to be filled
during the operation of the GRS facility which will eventually allow
more landfill gas to be generated. The capacity of the plant is
estimated to be between 1 and 2 million cubic feet per day with some
minor modification.
The gas is collected, filtered, compressed to about 6 psi and then piped
to the Generating Plant where it is used as a fuel in a steam power
plant supplementing natural gas.
Electrical
GRS began generating electrical energy in Northern California in 1983
with the 1 MW plant. By 1991 (figure l). approximately 44.5 MW were on
line selling power to the various utilities. The plant locations,
capacities and amount of gas processed per day are:
1This paper was presented in Melbourne, Australia, on February 27, 1992
L-l
-------
Location Capacity Gas Processed
MW MM cub. Ft. per day
Menlo Park, CA 2.0 1.5
Guadalupe, CA 2.5 1.9
Nevby Island, CA 5.0 3.8
American Canyon, CA 1.5 1.0
Mountain View, CA 3.5 2.5
Coyote Canyon, Orange Co., CA 20.0 14.0
Sycamore, San Diego, CA 1.5 1.0
San Marcos, San Diego, CA 1.5 1.0
Orange, New York 3.0 2.0
Kapaa, Hawaii 3.0 2.0
Santa Cruz, CA i.o J_
Total 44.5 31.4
GRS generates electricity front landfill gas using many different types
of generating equipment ranging from small multi unit reciprocating
engines, to gas turbines, and ultimately a steam turbine. (Figure 2)
In general, the technology was tailored to each particular application.
The first group of projects tended to use small 500 kv naturally
aspirated internal combustion engines. Since there were no similar
projects on the west coast when we began operating in early 1982,
engines were selected based on their simplicity and operating histories
in the closest similar environment. These were the Cooper Superior
straight 8's which had an excellent operating history in remote oil
pumping stations, drilling platforms, and many applications using fuels
with heat rates less than natural gas. The operating philosophy was
than many small units would be much more reliable in terms of
maintaining productivity, than one or two larger ones. Also, our first
landfill gas project at Menlo Park had been tested by one of our
competitors and found to not contain enough gas for economic production.
Cur concept was that if the gas supply decreased over time we could
reduce the number of units to correspond to the gas supply.
Finally, as our experience in estimating the volume of landfill gas
improved, we began to take greater risks in the number and type of prime
movers. The air quality and other environmental considerations also
began to play a larger and larger part in the selection of equipment.
Our largest project, the 20 MW steam turbine in Orange County,
California was built in the most restrictive air quality basin in the
U.S., and subject to all of the rules and regulations of the South Coast
Air Quality Management District.
^
The project was originally planned as 5 Solar Centaur gas turbines
generating approximately 15 MW. Air quality permitting quickly rejected
this technology as being too high in NOx emissions. The resulting
boiler and steam turbine was several magnitudes cleaner with NOx
emissions in the 15 to 20 parts per million.
1-2
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Figure 1
MW
GRS POWER OUTPUT
MW
1991
L-3
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FIGURE 2
GRS
TECHNOLOGIES
NUMBER
11
2
4
2
1
5
2
TYPE
8 CYLINDER NATURALLY ASPIRATED
COCPER SUPERIOR RECIPROCATING ENGINES
8 CYLINDER TURBOCHARGED COOPER SUPERIOR
LEAN BURN RECIPROCATING ENGINES
12 CYLINDER TURBOCHARGED WAUKESHA. LEAN
BURN ENGINES
OUTPUT
500 KW EACH
750 KW EACH
1100 KW EACH
16 CYLINDER TURBOCHARGED COOPER SUPERIOR 1750 KW EACH
LEAN BURN ENGINES
ELECTRIC STEAM TURBINE
SCLAR SATURN GAS TURBINES
SCLAR CENTAUR GAS TURBINES
20 MW
1000 KW EACH
3000 KW EACH
L-4
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Factors which we consider in developing a project
. Landfill Characteristics
•Markets
- Technology
• Environmental
1. Landfill Characteristics
Figure 3 lists the factors that should be considered in deciding whether
or not a landfill is worth developing. A landfill gas study is always
useful especially during later financing by banks and other
institutions. The issue of whether there is gas in the landfill and the
credibility of the engineer making the estimate becomes a very major
factor in determining now or if the project is financed. We have had
limited success in predicting gas and have tended to become more and
more conservative.
A beginning and relatively safe rule of thumb is to use the gas
generating factor of 0.1 cubic feet of gas per year from each pound of
refuse placed in the landfill. This only applies to landfills that
contain household refuse and are somewhat wet. Moisture content of the
refuse does play seme part in the volume of gas generated, although it
is unclear at this point just how important this is in the long run.
2. Markets
This factor probably more than any other determines if the project will
go forward, if there are no customers for the medium or high BTU fuel.
or the electricity produced by the project, nothing will happen.
Further, not only trust there by buyers for the product, but they must be
prepared to take as much as the landfill can produce. Purchase
contracts must be "take or pay" contracts.
The contract negotiation for the landfill gas or electricity produced
should be carried out immediately following the gas test of the
landfill. At this point, electrical generating capacity in KW, or
volume of cubic feet per day can be estimated. Curtailment provisions.
base energy rates, and escalators should be worked out since these will
be required by the financiers. Signed contracts are essential. Verbal
agreements are great, but signed contracts are bankable. Use of a good
energy contract attorney is highly reconmended. There is nothing worse
than trying to renegotiate terms and conditions the second and third
times. This creates time delays and more importantly, developer
credibility suffers.
L-5
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FIGURE 3
LANDFILL CHARACTERISTICS
MINIMUM GAS REQUIREMENTS FOR RECOVERY PROJECT
- In place tonnage: 2 million plus
- Depth of Refuse: 35 feet or more
* Type of Refuse
- Acreage: 35 plus acres
- Continued landfill operation for several years.
- Seal/cap material on landfill
- If the landfill is closed, how long did it operate
and when was it closed.
L-6
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Electrical projects in California and a number of other states have been
made much easier by the adoption of so called "Standard Offers" which
require utilities to purchase power from small cogenerators. Not only
are the terms and conditions set by the Public Utility Commission,
(PUC), but in sane cases the prices of electrical energy as well. The
contracts are usually "take or pay" and are relatively easy to
understand by the developer and the financier.
To foster the growth of cogenerators, in the mid 80's utilities offered
so called firm price offers or contracts. This fixed the price the
developer will be paid for this energy for a relatively long period of
time (10 years) and took away one of the major uncertainties in
financing landfill gas projects. In some contracts the developer has
the option of selecting either a fixed price per kwhr or a floating
price per kwhr contract, or a combination of both. In California, this
type of contract was called Standard Offer No. 4. The original S.O.
§4's created a gold rush of "blue suede shoe" developers. By the time
the PUC's/utilities realized their mistake, over 10.000 MW were signed
up.
Figure 4 shows the historic growth in both natural gas rates and
electrical rates since the 1970's. Although the figure shows the retail
price of energy it does serve to illustrate that in the case of
electrical energy, the price is projected to remain relatively level.
All of the statistics are fron PG&E which is one of the largest
utilities in the U.S.
The price of energy paid to the landfill gas developer is not however,
the retail price of energy. The cogenerator price, the so called
"avoided cost" is shown in figure 5. Simply, the avoided cost is the
cost the utility "avoids" by buying power from a cogenerator rather than
building its own facilities. It is defined as the product of the
utility's incremental heat rate and the marginal cost of the utility's
fuel.
This marginal fuel in the case of PG&E is either natural gas or oil or a
combination of both. Figure 5 also shows the fluctuations in the
avoided cost that have taken place since 1980. Not only does the
falling price of natural gas or world oil pricing effect the avoided
cost but also the utility's own heat rate. When PG&E started up their
nuclear powered generator (Diablo 1). in 1985, there was a significant
drop in the avoided cost primarily due to the decrease in the heat rate.
In effect, PG&E was able to shut down sore of the more inefficient power
plants in their system.
L-7
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Figure 4
Gas Rates (Real)
8
6
Dollars per DTh
PG&E CEC
1970 1975 1980 1985 1990 1995 2000 2005
Electric Rates (Real)
Cents per kWh
PG&E CEC
1970 1975 1980 1985 1990 1995 2000 2005
L-8
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Figure 5
c/kwhr
UTILITY AVOIDED COSTS
CKWHR
i:i!'ls I n
I'M SAO i i I ' '-all/I'
1980 - 1982 • 1984 i 1986 i 1988 : 1990 I 1992
1981 1983 1985.. 1987 1989 1991
L-9
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In addition to paying a price for the generated Jcwhrs. seme utilities
alsr pay a capacity payment. Very singly, this is a payment (based on a
generating turbine), paid to a cogenerator for having a reliable power
plant capable of delivering power at least 80% of the time during the
utilities' peak months. The capacity payment can be levelized depending
on the term of the contract and depending on how long the developer
thinks landfill gas in his project will last. Rates varied but were
generally between S100 to S200/kvyr.
In seme States, the capacity payment is simply added into the price of
electrical energy and is paid on a cent per kwhr basis. In California,
the capacity impact is approximately 1.5 to 1.8 cents per kvhr.
By the late 1980's even this vent away as utilities decided they had too
much capacity. Figure 6 is a comparison in between the fixed price of
Standard offer No. 4 and Standard Offer No. 2 in which there is no fixed
pricing but is based rather on the actual avoided costs that the utility
experiences. In 1985, in PG&E's area, the actual avoided cost of
Standard Offer No. 2 was consistently higher than Standard Offer No. 4.
By the time the world oil glut was felt in the marginal fuel pricing in
early 1986 this had reversed. As shown in figure 6, the current
estimates are that the actual avoided costs of Standard Offer No. 2 will
be below the higher rates of Standard Offer No. 4 for the foreseeable
future.
3. Technology
Type of gas collection system
There are many types of gas collection systems. The most conventional
is a system with vertical wells and horizontal collection headers spread
out over the surface of the landfill. The most effective and least
costly to repair are those in which the headers are on the top of the
landfill and are exposed. Many owners of landfills require that the
header system is placed underground. The cost of the gas collection
system significantly increases in this case since settlement in the
landfill causes collection system breakage which in turn results in
expensive excavation to gain access to laterals. In some cases it's
cheaper to just replace parts of the system altogether.
Trench collection systems have been shown to be effective in certain
instances as have pipe systems installed in refuse while it is placed in
the landfill. In many cases where we have tried horizontal systems.
breakages of the lines occurred and the lines were ultimately abandoned.
The quality and quantity of the gas generated using these systems was
also less than was observed with vertical systems.
L-10
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Figure 6
AVERAGE PURCHASE PRICE FROM QFs
(V
a
C
0/
U
Standard offer
Standard offer *2
May-79 Nov-84 May-90 Oct-95 Apr-2001
-------
If the landfill is open, additional problems have to be resolved in
designing gas collection systems that are compatible with the on going
refuse filling operation. How expensive this is ultimately is a
function of the attitude of the landfill operator. Lateral collectors
often cross roads which requires culverts and other types of
reinforcing.
On the basis of GRS's experience, the cost of the gas collecting system
is not the major expense in developing a landfill gas project. In
general, we have found that the cost of the collection system varies
between 10% and 20% of the total capital cost of the project.
The materials used for gas collection systems and their location on the
landfill are shown in Figures 7 ft 8. These statistics were developed
from a survey of most of the landfill gas projects in the whole U.S.
(Ref. 1) Most of our installations, similar to the national statistics
use pvc. and polyethylene in the gas collection systems. Over the last
several projects however, we have begun using High Density Polyethylene
which is stronger and less brittle than the other materials. Similar to
the national statistics, most of our collection systems are underground.
Gas Processing
The type of gas processing equipment is dependent on the product end
use. Variables such as hourly gas volume, pressure, filtration,
condensate removal equipment have to be determined for each landfill.
Volume of gas is simply the amount of gas that the collection system
removes from the landfill. All of the other variables are determined by
the requirements of the end user of the medium or high BTU fuel or the
engines used in generating electricity. Specific examples of the cost
of gas processing as the volumes and pressures increase are included
later in this paper.
Electrical generating equipment
The technology of electrical generating equipment is to a great extent
determined by the volume of gas available and the air pollution
requirements of the area in which the project is located. Internal
combustion engines begin at approximately 500 KW and go up to well over
3000 KW. A rule of thumb is that 1 million cubic feet of landfill gas
per day at 450 BTU per cubic ft. will generate from between 1250 to 1600
KW per hour.
"Clean burn" or "lean bum" technology is generally required by air
quality districts as being the most efficient in terns of reducing NOx
and CO pollution. The down side is that these engines also require over
90 psi in fuel pressure and increased maintenance to operate them.
L-12
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Figure 7
MMERIALS T1SF7) IN LATERAL/HEADER FIFES4
Status
Tvne of Material
Polyethylene (PE)
Polyvinyl Chloride (PVC)
High Density
Polyethylene (HDFE)
PE and PVC
Other Material
Total %
(Total f)
pi aj^nffi
38.9%**
22.2
33.3
0.0
9.6
100.0
(18)
Existing
48.0%
31.0
6.0
13.0
2.0
100.0
(100)
All Facilities
46.6%
(55)
29.7
(35)
10.2
(12)
11.0
(13)
2.5
(3)
100.0
(118)
*Survey based on average of 170 projects.
No information was available from 39 projects with respect to lateral/
header piping materials.
**Percentage of column.
L-13
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Figure 8
OF LATERAL/HEADER PIPES*
Tvoe of M3terial
Above Ground
Below Ground
Above and Below
Ground
Total %
Planned
11.8%**
82.4
5.9
100.0
(17)
Existing
23.5%
66.7
9.8
100.0
(102)
All Facilities
21.9%
(26)
68.9
(82)
9.2
(11)
100.0
(119)
'Survey based on a sunroary of 170 projects.
No information was available from 38 projects with respect to location
of lateral/header pipes.
"Percentage of column
L-14
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Gas turbines tend to be smaller than the corparable sized Internal
combustion reciprocating engines and have better emission
characteristics. A negative is that the gas inlet pressure requirement
can be well in excess of 100 psi. Consequently, turbine installation
have high parasitic loads. Historic operating statistics indicate that
while the turbines are trouble free, the gas processing and filtering
equipment is the high maintenance item.
Interconnect
The electrical interconnection between the utility and the project can
be quite expensive especially if the utility has to make modifications
to its substation. As much of the interconnect should be built by the
landfill gas developer as possible. This saves tine and is generally
much less expensive than if the utility does it. Lead times for
California utilities tend to be well over 6 months from beginning
planning to final construction. This should be included in the
development schedule.
4. Environmental concerns
The environmental concerns for project development of a landfill gas
project are listed in figure 9. Project development begins with land
use permitting, air quality permits and water quality permits. Each of
these need specific information on the project such as the number and
type of engines proposed, type of gas processing, emission levels of all
pollutants and volumes of condensate generated. Detailed engineering is
not required until after all of these permits are obtained.
Once the above three types of permits are received, detailed plans and
specifications can be prepared and submitted to the local building
departments for review. Although this can be time consuming, permits
are generally given for projects that are considered environmentally
sound. If the permit and detailed engineering phases are done
sequentially, the project can take well over a year for these two phases
alone prior to construction. GRS has generally submitted all of the
permit applications and at the same time has continued with detailed
engineering. The ideal .is to receive the water quality and emission
permits at the same time as the building permit. A risk in trying to
carry out several functions concurrently is that detailed engineering
may have to be redone several times to comply with the requirements of
the local jurisdictions reviewing the submittals.
L-15
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Figure 9
CONCERNS
PCR PROJECT DEVELOPMENT
- LAND USE PERMIT
- Corrpatibility with land use on and around landfill
- Noise
- Fire Protection
- Flooding/Drainage
- Foundations
- Other Environmental Inpacts
- AIR QUALITY
- Landfill Emissions
- Migration Control
- Emissions of NOx, CO from LTO Project itself
- WATER QUALITY
- Disposal of Condensate
- BUILDING PERMITS
- Foundations
- Building Type, Appearance
- Noise Insulation
- Fire Protection
- Security
— Landscaping
L-16
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5. Lggg^/ciiiiiitfujlal concerns
A list of these factors is shown in figure 10. The gas lease agreements
and power purchase agreements will determine how easy the project will
be to finance later on. An important issue is the assignability of the
contracts. If limited partnerships are set up, the contracts must rake
provisions to allow a new legal entity to step in and take over all of
the obligations of the primary developer. Utilities are generally
nervous when this happens and require in sore instances recourse to the
original developer in the event that the partnership has a problem.
This is especially true in levelized capacity contracts which include
penalties for non performance.
Another issue includes the term of the contract. The gas lease and the
power purchase agreement should have the same time period.
As regulations relative to the migration of landfill gas become more and
more stringent, the liability and who assumes it can become a major
negotiating point. If possible, landfill gas developers should attempt
to mitigate against gas migration and the emissions from the landfill
but the ultimate responsibility should remain with the owner of the
landfill. Who ultimately has the responsibility will affect the
financing of projects. Long term environmental impairment insurance is
either very expensive or not available. Bankers tend to view this
negatively.
The tax issues, such as who takes the Production Tax Credits (PTC), can
affect the financial attractiveness of a project. The internal rate of
return of a project which takes these tax credits can be significantly
increased. For private landfills, the Production Tax Credits could be
used in lieu of royalty and can be worth much more than the royalty
income. Whether these credits will continue past the year 2000 remains
to be seen as the U.S. Congress reviews the whole question. Currently.
a landfill generating 1 million cubic ft. of landfill gas per day would
yield over Siso.ooo per year in Production Tax Credits.
The issue of PTC's has had a significant impact on the development of
landfill gas projects especially by those company's that had an
appropriate tax appetite. In fact, projects that had normally negative
cash flows could become profitable primarily due to the PTC's.
Capital Costs
GRS's historical cost of electrical generating plants while originally
decreasing started to increase from 1985 on steadily decreasing per
installed KW as shown in Figure 11. In 1983, when GRS's first
electrical generating project was built at Menlo Park, California, the
total cost of the project was a little over $1.25 million per MW output.
This included the gas processing, filtration equipment, gas collection
system (50+ wells), electrical interconnect, all internal combustion
engines, generators, all switchgear and building to house all of the
equipment.
L-17
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Figure 10
EEGAL/CQWERCIAL CONCERNS
FOR PROJECT DEVELOPMENT
- GAS LEASE AGREEMENTS
- Term of Agreement
- Royalties
- Assignability
- Environmental Liabilities
- POWER PURCHASE AGREEMENTS
- Following Interconnect Priority Procedures
- Curtailment Provisions
- Pricing
- Penalties - Long Term
- Assignability
TAX ISSUES
- PRODUCTION TAX CREDITS
L-18
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In 1984. when two additional projects were built, at Guadalupe, Santa
Clara County. Ca and Newby Island, San Jose, Ca, the total installed
cost was over $1.15 million per KW output. This cost was further
reduced to SI.07 million per MW in 1985 when two more plants were put on
line at American Canyon. Napa, Ca, and Mountain View. Ca.
In 1988, the 20 MW Coyote canyon steam generating plant cost $1.3
million/MW. Again, this Includes a fully operational power plant with
all buildings and landfill gas collection system as veil as all of the
changes that occurred due to plant modifications resulting from air
quality issues.
Gas Processing costs
Figures 12 and 13 show our experience in gas processing. The primary
determinant in gas processing equipment is the volume of gas that is
processed per day. A secondary variable is the processing pressure. A
plant handling 5 million cubic feet of landfill gas per day at 70 psi is
5 times as expensive as one handling 1 to 1.5 million cubic feet per
day.
Operating Costs
Figure 14 shows our operation cost experience over the last 8 years.
When we began operations with new equipment in 1982, operating costs
were a little less than 2 cAwhr; last year (1991), they had increased
to about 2.7 c/kwhr, which represents about a 4% per year compounded
growth rate, or a growth rate consistent with inflation. These figures
include all of the reciprocating projects. Additionally, the overall
operating costs have been increasing steadily over the last 4 years or
so following a buildup of a maintenance organization capable of carrying*
out more and more of the engine maintenance and operations functions.
Additionally, the 2.7 cAwnr includes all of the field maintenance.
operations and monitoring required to operate the projects.
We have found that there is no such thing as an unmanned plant. The
only way that 80 to 85* capacity factors can be maintained is by having
a plant operator present at least 8 hours per day. (An 80% capacity
factor as we define it, means that the plant is producing at its rated
output during 80% of the total number of hours in a year.) The function
of the operator is to assist in general maintenance of the engines and
to repair the gas collection system. .
The steam generating project has not been included in these statistics
since it is manned 24 hours per day, 7 days per week and uses a
different technology. Its operating costs have tended to be about 15%
less than the small reciprocating plants. Although GRS has 5 gas
turbine projects, the total operating time has not been long enough to
establish any kind of history. Thus far however, we believe that the
gas turbine plant operating costs will be conparable to the
reciprocating projects.
L-19
-------
Figure 11
$/MW
(MILLIONS)
1.5
1.4
1J
1-2
1.1
1
0.9
08
0.7
06
0-3
04
03
0.2
01
0
ELECTRICAL PROJECT
COST PER MW
SSfiSSg.X
r-xvxwx-
•vBfiffiH'.v
• •%%%••••
:2xix&
ss-m
x-x<-x°2
Ml
1983
1984
.•-•.-.• -.-.NV
>>:•:•-S:::::
^« • • • • • • i
SSSS:
%¥fe^«
i§E§fe"®
1988
1990
L-20
-------
Figure 12
GAS PROCESSING COSTS
VERSOS PRESSURE. VOLUME OF GAS
Project
Bradley*
Menlo Park
Guadalupe
Newby Island I
American Canyon
Mountain View
Nevby Island II
Madiura BID
Rotary Lobe
Reciprocating Conp.
Dollar Cost
(1,000's)
1.000.000
25.000
150.000
80.000
222.000
372.000
300.000
220.000
250.000
Pressure
(psi)
70
2
25
8
90
90
45
14
20
W Cu ft/day
Gas Vol.
5.0
1.4
1.1
1.4
1.0
2.3
2.0
1.89
1.89
*Built by GRS but sold in 1990,
Figure 13
GAS COMPRESSION COST
VS PRESSURE
S (MILLIONS}
Vol: 5 MM
cu ft/day
Vol: 1.5-2.0
MM QJ ft/day
Vol: 1-1.5
j MM cu ft/day
-30 40 SO SO 70 60
PRESSURE OUTPUT (PSG)
L-21
-------
Figure 14
C/KWHR
3
2.8
2.6
2.4
2.2
2
1.8
1.6
1.4
1.2
1
0.8
0.6
0.4
0.2
0
1984
OPERATING COSTS
AUL PROJECTS
I
1965
1986
1988
1989
1987
YEAR
LABOR - MAINT& REPAIR o MISC/ECUIP. LEASE
1990
1991
TOTAL
L-22
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When we began operating, ve believed that given the requirement of an
operator at each plant, as the size of the plant increased, labor costs
would tend to decrease as a percentage of total operating costs. This
did not happen because as the size and complexity of the plant increased
so did the size of the gas fields, engines, and gas compressor/
refrigeration systems required to fuel the engines which in turn
required considerably more labor to operate them. As emission
requirements became more and more restrictive, low compression systems
changed to high compression systems, and naturally aspirated engines
changed to high compression turbocharged engines.
The three major components of operating costs include labor,
maintenance/repair (this includes parts, consumables such as oil. and
any work done by outside contractors), and miscellaneous equipment
leases. The last category includes leasing and rental of equipment such
as backhoes, pipe welding machines and any other type of specialized
equipment. Other cost components that make up the total operating costs
include site specific variables such as property taxes, utilities.
insurance and other miscellaneous costs.
Total Capital Cost
For the purpose of evaluating a hypothetical 1.000 kv project, a capital
cost distribution shown in figure 15 was assumed. Further, the assumed
project total cost is $1.5 million per MW output. Based on GRS
experience, the breakdown of the cost is fairly accurate and represents
how the $1.5 million would be allocated. The gas collection system is
approximately 13% of the total project cost; 80% is the cost of the
equipment and building. This includes all gas processing equipment,
engines, generators, switchgear and building to house the equipment on a
fenced half acre site. The balance or 7% of the project cost is for
interconnect, legal and environmental fees.
Income statgnent/operatlng cash flow
The income statement for a typical operating year for the hypothetical
1.000 kv plant is shown in Figure 16. Also listed are the assumptions
including the electrical sales rate (7.0 cents/kvhr). and royalty (10%).
and on line time. (80%)
The net income after tax (at 50%) is, approximately $61.000. The
operating cash flow, once depreciation is added back to net income, is
almost $211,000.
The Internal Rate of Return. (IRR) as defined in this paper is the rate
of return in which the discounted operating cash flow over the first 10
years of the project is exactly equal to the original investment.
L-23
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Figure 15
CAPITAL
HYPOTHETICAL 1.000 KW PLANT
Item Cost %
COLLECTION SYSTEM $ 200,000 13.3
FEES-PLANNING/ENVIRONMENrAL 15.000 1.0
LOCAL FEES 15,000 1.0
INTERCONNECT COST 75,000 5.0
GENERATING EQUIPMENT 970.000 64.7
CONTINGENCY 225,000 15.0
TOTAL 51,500,000 100.0
L-24
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Figure 16
ECONOMICS OF 1,000 KW ELECTRICAL GENERATING PROJECT
ASSUMPTIONS
KW OUTPUT (NET) 1,000
CAPITAL COST 1,500.000
GAS REQUIREMENT CFT/DAY 700,000
ON LINE TIME 60%
OPERATING COSTS C/KWHR 2.0
ELECTRIC RATE C/KWHR 7.0
KWHRS/YR 7,446.000
ROYALTY 10.0%
DEPRECIATION (YEARS) 10
TYPICAL INCOME STATEMENT
REVENUES $490,560 100.0%
EXPENSES
OPERATING COST 140,160 28.6%
ROYALTY 49,056 10.0%
SUBTOTAL 189,216 38.6%
GROSS MARGIN 301,344 61.4%
SG&A (6%) 29.434 6.0%
DEPRECIATION 150.000 30.6%
OPERATING PROFIT 121,910 24.9%
TAX (50%) 60,955 12.4%
NET AFTER TAX 60.955 12.4%
DEPRECIATION 150.000 30.6%
OPERATING CASH FLOW 210,955 43.0%
L-25
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In computing the IRR, a number of additional assumptions have been
incorporated. The assumed operating costs do not include major capital
investments in the project that will be required over its operating
life, vhich in this case has been assumed to be 10 years. These
investments include major engine overhauls, and major repairs to the gas
field such as additional gas wells and/or major replacement of a
significant portion of the field.
Our experience has been that a 1 Miff plant would cost about $80,000 to
carry out a complete major engine overhaul after 3 years of operation.
Typically, major gas field investment tends to occur about 4-5 years
following the original installation. Consequently, in evaluating the
financial feasibility of a project we capitalize the investment in
carrying out both the engine overhaul and gas field repair and
depreciate each of these investments over 3 and 5 years respectively.
Finally, in evaluating the effect of various parameters on the internal
rate of return, and return on net assets, the effect of financing has
been neglected. Throughout the analyses I have assumed that 100%
equity.
Factors Influencing Tntetnal Rate yf Rgturn
Figures 17 to 20 illustrate the effect of various assumptions on the IRR
of projects.
Enerov pricing (figure 17) is by far the greatest influence on the IRR.
At 7 c/kwhr each 1% increase in the price of electrical energy per year
results in about a 10% increase in the TRR. Operating costs, (figure
18) effect the return to a much lesser extent. A 10% decrease in the
operating cost results in approximately 8% increase in the TRR.
Decreasing capital costs (figure 19) has a similar effect. A 10%
decrease in capital expenditure at the beginning of the project results
in improving the TRR by 20%.
Improving operating on line time has somewhat greater impact on TRR. A
10% change in operating on line time results in approximately a 20%
change in TRR.
Finally, taking advantage of the Production Tax Credits can also have a
significant impact on the TRR since the credits can be worth several
million dollars over the life of the project.
o&s
The future of landfill gas projects is very dependent, as it has always
been on the sales price of the product whether that is electricity or
medium BIU fuel. Based on GRS's experience, landfill gas projects need
to be over 1 MW. and have an electrical price of at least 6 to 7 cents
per Jcwhr including any capacity payments. Royalties, at this energy
pricing should not be higher than 12.5%. If higher royalties are
offered, the percentage should be a function of energy pricing. over and
above the b^g* energy rate as inflation takes place.
L-26
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Figure 17
30%
28%
IRR%
ENERGY PRICING
EFFECT ON OW
8c/kwhr
7c/kwhr
6c/kwhr
10%
At 7c/kwhr. each 1% annual increase in energy revenues results in
about 10% increase in the IRR.
1-27
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Figure 18
30%
28%
26%
IRR%
•zn
OPERATING COST
ErFcCTCNIfW
0% 10%
% CHANGE
At 7 c/kwhr energy, a 10% decrease in operating costs
results in an 8% increase in IRR
20%
8 c/kwhr
7 c/kwhr
6 c/kwhr
L-28
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Figure 19
-20%
CAPITAL COST
EFFECT ON IRR
-10%
Sc/kwhr
7cykwhr
6c/kwhr
10%
0%
% CHANGE
At 7 c/kwhr energy, a 10 % decrease in the capital cost
results in approximately a 20% increase in the IRR
20%
L-29
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Figure 20
IRR%
2% I
0%
-2C%
ON LINE TIME
EFFECT CNIRR
05%
I
0%
5%
->C% -5%
% CHANGE
At 7 c;kwhr energy, a >0% decrease in On Une time
results in an over 20% decrease in the IRR
8c/kwhr
7c/kwhr
6c/kwhr
10%
L-30
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Projects should make economic sense without the tax credits. Further,
evaluation and economic analysis should be done over a 10 year period.
The IRR of projects should be as high as possible excluding the cost of
money, if all of these conditions are met the project has a fairly good
chance of succeeding, provided however that the on line time is over 80%
per year.
Future problems for landfill gas projects which will add to the capital
costs are all of the environmental concerns that have to be satisfied.
The reduction of emissions frcm the projects and the treatment of
condensate all cost a great deal of money but add nothing to the
revenues.
Operating costs must be controlled. We have found that the only way
that this can be done is to develop a maintenance staff and carry out
all of the equipment repairs in house. Unless plant operations
personnel are available 24 hours per day to respond to problems, the
capacity factor cannot be kept over 80%. A kvhr not produced is lost
forever. The plant cannot be run to catch up.
In summary, gas recovery projects can be developed and developed
profitably, not only for the developer, but also the landfill owner if
some of the basic economic realities are kept in mind and both are
willing to work together.
L-31
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References
Berenyi, Eileen.. Gould Robert., 1991—92 Methane Recovery Fran
YftfUt'9Qlc- published by Governmental Advisory Associates* 1991
L-32
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APPENDIX M
WASTE MANAGEMENT OF NORTH AMERICA, INC.
LANDFILL GAS RECOVERY PROJECTSi
Michael A. Markham
SEC Donohue - Oakbrook Division
Lombard, Illinois
INTRODUCTION
Organic materials contained in garbage that is disposed of in sanitary landfills throughout
the U.S. decomposes by an anaerobic (oxygen deficient) bacterial process which emits gas
as a byproduct. This gas, commonly known as landfill gas (LFG), is composed primarily of
methane (45-60%), carbon dioxide (35-50%), nitrogen (0-10%), and oxygen (0-2%). In
addition there are many minor volatile and sulfur bearing constituent compounds found in
LFG. Landfill gas is colorless, however, it does possess a pungent odor. The specific gravity
of LFG is very close to that of air, therefore it does not readily rise or sink when released to
atmosphere.
LFG does not pose a threat to society as long as it remains within the landfill or is controlled
properly. If LFG should leak through the landfill surface, or through a break in the landfill
ground liner, it could seep through surrounding soil formations and accumulate in pockets
creating the potential for an explosion. In addition, EPA has determined that LFG contributes
significant quantities of methane to the atmosphere which increases the global warming
effect.
A positive aspect of LFG is its content of methane which Is also found in natural gas. The
heat content of LFG, by direct relationship of its methane percentage, is about half that of
natural gas. However, there are many applications where natural gas as the traditional fuel
can be substituted directly with LFG. Waste Management of North America, Inc. (WMNA)
has committed itself to utilizing LFG to produce usable energy from what was once a
wasted resource. WMNA is committed to the development of LFG recovery plants wherever
they are economically feasible. WMNA uses landfill gas primarily for the production of electric
energy, and in a few cases, for direct sale of medium BTU gas for boiler or process fuel.
Where the project economics prohibit a positive return, most sites resort to collecting and
burning the LFG in a flare.
iThis paper was presented at SWANA's Fifteenth Annual Landfill Gas
Symposium held in Arlington, Virginia on March 24-26, 1992.
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LANDFILL GAS ASSESSMENT
Prior to developing any LFG recovery project, the volume of gas available must be quantified,
or a reasonable estimate established, in order to size the plant and choose the necessary
equipment. This estimate will also be required when negotiating a power or gas sales
contract with an electric utility or end user.
There are three ways to estimate the quantity of gas that can be generated within and
recovered from a landfill: (1) model theoretical gas production, (2) conduct an active LFG
flow test, and (3) install and maximize gas from a full LFG collection system. The first
method involves using known information about the tonnage and make-up of the refuse
material placed in the landfill over its life. Other factors include the integrity of the landfill
cover material and the moisture content of the refuse. Information can be estimated for
past data if unrecorded, and for future data, to establish a gas generation curve over thirty
(30) years. Obviously, materials that are readily decomposable, such as residential trash,
paper pulp and sewage sludge, will decompose faster and generate gas at a quicker rate
than other materials such as industrial waste, plastics and construction debris. Landfills
containing more of the rapidly biodegradable materials will tend to have faster gas
generation rates and, therefore, gas generation curves that rise quickly, peek early and drop
off rather steeply. Other landfills with materials which will decompose more slowly will have
lower gas generation rates and generate less gas early, but extend usable gas production
for many more years.
The moisture content of the buried refuse and landfill surface integrity will also greatly affect
the rate of decomposition, and thus gas generation, and must be considered a major factor
when estimating LFG generation rates. Very moist, saturated materials tend to provide an
ideal environment for the microbes that carry out the bacterial process that change
complex organic compounds into methane and carbon dioxide. Dry refuse will be slow to
decompose and generate methane. Modem landfills, by virtue of design, are liquid tight due
to the principal of "the less liquids in. the less chance of liquids out.' This is primarily a
response to older, poorly designed landfills whose liner and surface cover allowed landfill
liquids to escape into the soils and underground water table. Because of their inherent
design, state of the technology landfills have been likened to tombs' of garbage, that
without liquids will never decompose, reduce in volume, and remain monuments of our
society. 2
For LFG generation, liquids are essential. However, for LFG collection, liquids can be a
detriment and therefore should be studied closely when determining the recoverability of the
2New sites with the composite liners as required by Subtitle D of RCRA can
enhance landfill gas production through leachate recirculation and other landfill gas
enhancement approaches. However, the majority of existing sites do not have
composite liners.
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LFG generated within the landfill. High liquid levels within a landfill will reduce the amount of
slot line which can be designed into LFG wells and thereby reduce the available area that can
be influenced under vacuum. In a new well with low liquid levels, the suction of gas to the well
can draw landfill liquids to the well that not only drown slot line, but also carry silt and debris
to the well and infiltrate its gravel pack, thus reducing the well's effectiveness even if liquid
levels can later be lowered. For WMNA LFG recovery, landfill liquid levels have been the major
difference for many projects between efficient gas recovery and a continual struggle of
replacing watered out wells.
The WMNA LFG program started in 1982 with one test crew dedicated to determining the
amount of LFG at WMNA sites. During the period of 1986 through 1988 when WMNA
employed three LFG test crews to travel the U.S. and conduct LFG flow tests to support or
contrast existing theoretical gas generation curves. Typically, a series of three to four wells
and four to five shallow probes per well were drilled in the landfill in a triangular or diamond
pattern. Gas was then extracted from the wells for several weeks or months at varying
vacuum levels while taking gas samples, temperature and flow readings at each well, and
pressure readings at each probe. From this data, as well as an examination of the material
that was removed during the drilling of each well, a gas generation model for the entire
landfill was extrapolated.
WMNA soon discovered that good collection system considerations were as critical as good
estimates of gas production in Veal world" experiences. Inconsistent designs and improper
installation of gas collection systems, as well as changing landfill operating patterns, caused
some recoverable gas estimates to fall short and facilities to be oversized. This lead WMNA
to realize that the best estimate of available gas could be obtained with the installation of a
complete LFG well field, collection system and flare. The flare blower pulls a vacuum on the
well field and the gas flow to the flare is measured using either orifice plate differential
pressure readings or a Pitot tube pressure measurement. From this actual flow, the LFG
recovery plant can be sized to accurately reflect the condition of the gas collection system.
This method of determining available LFG, though definitely more accurate, takes much longer
and requires more up-front resources (i.e. design and installation of well field, gas collection
system and flare).
LFG PROJECT DEVELOPMENT
Economics
The economics of all potential WMNA gas recovery projects are examined closely over the
life of the pending electric or gas sales contract, typically ten years. Using estimates for
initial capital expenditures, electric sales revenue, income tax credits for renewable energy
usage, and predicted costs and schedules for equipment maintenance, a complete project
"proforma" is developed to determine the financial return. A discounted cash flow payback
period of ten years or less is desired for project development. However, intangible benefits,
such as positive public relations and environmental image, are always considered.
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Electric Power Plants
To date, WMNA has twenty-one (21) landfill gas to electric energy plants and four (4)
medium BTU LFG sales facilities. Electric generation plants have been the most attractive to
develop, however not without drawbacks. Electric utilities are located everywhere, so finding
a reliable customer for the electric energy is not difficult. Most landfill gas projects hinge on
the price of the electric sales to the local electric utility, which can vary widely across the U.S.
The electric energy is sold to the utility in the service area of the landfill. By virtue of being a
small power production "qualifying facility", utilities are required to buy the electricity as
mandated under the Public Utilities Regulatory Policies Act (PURPA). However, the Federal
Energy Regulatory Commission (FERC) rulings have stipulated that the utilities only have to
pay the "avoided cost" of energy they currently produce, (i.e. the cost of their displaced
fuel) or new capacity. As a result, not all utilities offer buy-back rates that can make a
project viable. Buy-back rates can be flat rates throughout the year, may have on-peak and
off-peak time variations, or may have seasonal variations. When the utility company is
facing the need for added generating capacity, a capacity payment may be obtained for the
reliable delivery of a committed power level. In some cases, the electricity can be
transported through one utility's system and sold to a second utility, otherwise known as
"wheeling" power. For most project development, the lowest allowable average levelized buy-
back electric rate is approximately $0.025 per kilowatt-hour (kW-hr). If a reasonable
electric rate can not be found in the area, most projects are not developed.
Gas Sales Plants
The second alternative pursued by WMNA for utilizing LFG as a renewable energy source is
the sale of the gas to an end user for fuel in a boiler or other process stream. The primary
hurdle to developing a LFG sales facility is locating a consistent user of the gas within a
reasonable distance of the landfill. Finding a customer that will be willing to take all of the
LFG that the landfill can deliver, twenty-four hours a day, year round, is a major difficulty. If
the customer is intermittent or cannot use all of the recoverable gas. then the gas must be
collected and flared in order to control gas migration. The landfill's cost to collect and flare
the gas for control is basically the same as for gas recovery, however, no sales revenue is
being generated. Large industries such as automobile and chemical plants that operate
around the clock are good potential customers. However, the landfills must be located
within a few miles of such facilities. Other potential users of LFG are trash burning power
plants and incinerators that can utilize LFG as a base fuel to perpetuate and stabilize the
burning of the waste materials. For most projects, a reasonable LFG price for both the
landfill and the customer can be reached; as with most cases, the LFG would displace
another fossil fuel such as coal or natural gas. The price of the gas would reflect the
landfill's need to offset the cost of installing and maintaining the LFG well field/gas collection
system, gas compression/cleanup system, and gas delivery pipeline depending on how the
agreement is structured. In the final analysis, the location of a reliable user of the LFG within
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a fairly close proximity to the landfill is the major obstacle for developing a medium BTU gas
sales plant.
Production Tax Credits
Another principle factor that has enhanced the potential for developing LFG projects is the
U.S. Federal Government Production Tax Credits (PTC) for renewable energy sources such as
landfill and bio gases, and waste gases from oil wells, natural gas wells, and coal mines.
These PTC's are based on the "barrel of oil equivalent" (BOE) of energy that is produced. A
typical 3 megawatt (MW) turbine/generator using 2.0 million standard cubic feet per day
(MMSCFD) can generate close to $325,000 in PTC's per year. Because the PTC's are applied
on an after-tax basis, their equivalent value on a pre-tax income basis are much greater.
PTC's account for approximately one-third of the revenue stream for a typical LFG project.
By current law, there are three principle rules that must be adhered to in order for a landfill
to qualify for the PTC's through the year 2002:
1) The gas collection system must be substantially complete by the end of 1992.
Most landfill gas collection systems that will be designed and installed strictly as
a result of the new U.S. EPA Clean Air Act regulations, will not qualify for PTC's
unless the qualification date is extended.
2) The landfill gas must be utilized for a beneficial purpose (i.e. power, steam or
heat production that would otherwise require another source of energy).
3) The benefit from the use of the landfill gas must be gained by others beyond
the recipient of the PTC's (i.e. landfills cannot generate power for their own
operations and claim PTC's for the gas). Primarily, landfills must sell the gas, or
the rights to the gas, to an unrelated third party.
WMNA takes advantage of the PTC's at LFG fueled electric power plants by selling the gas to
a third party* joint venture between WMNA and Caterpillar Financial Corporation (CAT
Financial) called Bio-Energy Partners (BEP). WMNA develops the project and builds the plant.
Soon after the plant is operating, CAT Financial acquires all of the equipment and the power
producing portion of the facility from WMNA. WMNA .then sells LFG to BEP, who in turn
produces the electric energy and sells it to the utility. BEP also make lease payments for the
use of the equipment to CAT Financial. WMNA maintains the role of managing partner by
operating and maintaining the facility and LFG well field/collection system.
Lobbying efforts are being made to convince U.S. Congress to extend the qualification
deadline for the PTC beyond 1992 and to extend the tax credit period beyond the year
2002. If the PTC's are not extended or replaced by other incentives many of the potential
LFG recovery projects, at WMNA sites and otherwise, will probably not be developed for
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energy production. The landfills required by the proposed EPA Clean Air Act regulations to
collect and control LFG emissions may opt to install the much less expensive equipment
necessary only to dispose of the gas by flaring. This would be a great loss of a relatively
untapped alternative energy source.
LFG RECOVERY PLANT EQUIPMENT
Standard Designs
In 1987, the WMNA landfill gas recovery program had estimated the potential for up to
eighty (80) gas recovery plants by the early 1990's. To better prepare, WMNA adopted a
philosophy of using a "standard plant" design to offset repetitive architectural and
engineering costs associated with the design of such a large number of facilities. The
"standard design" primarily incorporates separate fuel gas collection/compression
system(s) room, gas turbine or engine/generator(s) room, a viewing room and/or control
room, all enclosed in a concrete block building. Located outside would be the utility
interconnect with high voltage transformer and switchgear, as well as some of the ancillary
equipment such as turbine air intake filters, engine radiators, exhaust silencers, gas aerial
coolers, and waste liquid holding tanks. The fuel gas compressor room is designed to meet
National Electric Code (NEC) Class 1, Division 2 requirements for hazardous environments.
The motive for the use of the concrete block is two fold; first, to provide maximum noise
attenuation from the operating equipment, and secondly, to provide an aesthetically pleasing
image for public relations purposes. Some of the more recently built facilities, mostly the
smaller plants, have modified the "standard design" to reduce project capital costs in order
to generate a more attractive financial payback over the project life.
WMNA's twenty-three LFG fueled electric power plants all use combustion engine technology
developed by either Solar Turbines, Inc. of San Diego, California (gas combustion turbines),
or by Caterpillar Inc. of Peoria, Illinois (internal combustion reciprocating engines). At these
twenty-three sites, WMNA has twenty-five (25) Solar Centaur turbines (4500 hp, each), two
(2) Solar Saturn turbines (1200 hp, each), and twenty-four (24) Caterpillar 3516 SITA
engines (1138 hp, each). The installed capacity of these electric generators is approximately
96 MW of power. Through the end of January 1992, this equipment had accumulated nearly
750,000 hours of operation.
After the initial turbine plants were installed in Wisconsin in 1985 (Omega Hills and Metro)
and the initial engine/generator plant was installed in Colorado in 1986 (County Line),
Caterpillar and Solar Turbines continued to improve the technology that had been developed
for LFG fuel service. Caterpillar continued to make adjustments to the engines to ensure
necessary maintenance and overhaul intervals would be cost effective. Solar continued their
development of the Saturn turbine that allowed WMNA the option of a smaller LFG fueled
turbine/generator unit. Based primarily on the commitment of these two companies to
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WMNA's LFG recovery program, the Solar Centaur turbine and the CAT 3516 engine were
chosen as the standard equipment for future LFG fueled power generating facilities.
Utilizing standard model equipment at the plants allows for shared experience to minimize
duplication of the learning curve, allows holding joint training seminars for plant operators
from around the country, and makes possible common stocking of major spare parts. All
equipment operating problem details from the WMNA plant monthly operating reports can
be pooled to determine if a particular problem experienced is identical among all units and, if
so, a common solution can be engineered to resolve the matter. WMNA also holds annual
seminars for their plants operators to provide training and information on subjects such as
turbine, engine, and compressor operations and maintenance, electrical system trouble
shooting, plant safety, lubricating oil analysis, and environmental policies and procedures. In
addition, open round table discussions are encouraged to have operators share new ideas,
air common grievances, and promote cooperative relationships between facilities. Lastly,
WMNA stocks a spare turbine engine and gearbox, spare blowers, compressors, large
compressor electric motors, and a spare reciprocating engine in order to reduce downtime
resulting from major equipment failures. If the equipment at each plant were different, each
site could not afford to stock their own spares. Awaiting equipment repairs or new
equipment from the factory at the time of a failure could cost the program hundreds of
thousands of dollars in lost electric revenue and tax credits each year.
Turbine/Generator Standard Equipment
The most widely used turbine/generator at WMNA plants is a Solar Centaur GSC4500 LFG
fueled turbine/generator set. The turbine is a slightly modified natural gas, simple cycle,
single shaft, industrial turbine engine; the only major modification made to the natural gas
version turbine was to double the fuel gas control system components and fuel injectors and
to enlarge the fuel gas manifold in order to account for the LFG fuel having approximately
one half the heat value of natural gas. The turbine/generator set is rated at 4500
horsepower (hp), and is supplied with a 3000 kW generator, 4,160 volts, 60 hertz, 0.8
power factor. The turbine at rated output and standard conditions (600 feet above sea
level, 50 degrees Fahrenheit (°F) ambient air temperature and standard inlet and exhaust
duct losses) requires approximately 40 million BTU's per hour (MMBTU/hr), lower heating
value (LHV), or about 2 MMSCFD of landfill gas at 480 BTU/SCF.
The other turbine/generator set in use by WMNA sites is a Solar Saturn GSC1200R LFG
fueled turbine/generator. This turbine model is an exhaust heat recuperated cycle turbine
rated at 1200 hp. Again, the turbine is basically a natural gas turbine with a modified fuel
system to account for the lower heat value of the LFG fuel. The electrical generator is rated
,at 950 kW. The Saturn typically requires approximately 11 MMBTU/hr (LHV) at rated
output and standard conditions. Both Saturn turbines at WMNA plants are installed as the
Second turbine/generator unit at the site.
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Engine/Generator Standard Equipment
As mentioned previously, WMNA uses the Caterpillar 3516 SITA engine at facilities where
reciprocating engines are installed. This engine is a slightly modified spark-ignited natural gas
engine, four stroke cycle, V-16 cylinder configuration, turbocharged aspirated, and after
cooled. The engine is rated at 1138 brake horsepower (bhp), operates at 1200 rpm
synchronous speed, and is supplied with an 800 kW generator, either 480 or 4160 volts.
Two versions of the CAT 3516 SITA engine are currently available. One version, the "high
pressure" model, requires 35 pounds per square inch gauge (psig) fuel pressure to the
engine where a standard type carburetor mixes the fuel and combustion air. The second
version, a "low pressure" model, requires only 2 psig fuel pressure at the engine where the
fuel/air ratio is controlled in a special mixing valve at the air intake prior to the
turbocharger. This "low pressure" model retains the full power rating of the standard engine
and actually uses slightly less fuel. However, the primary advantage of the "low pressure"
model is the lower power consumption of the landfill gas collection/compression system that
must compress the gas to only 2 psig verses 35 psig for the standard "high pressure"
model.
The exhaust from the CAT 3516 engines is not cataliticly treated, however, the engines do
utilize lean-burn technology that allow nitrous oxide (NOX) emissions to approach Caterpillar
quoted levels of 2 grams per brake horsepower-hour (g/bhp/hr) for the "high pressure"
engines. Field exhaust emission tests on "low pressure" engines have shown that NOX levels
of 4 g/bhp/hr are easily achievable. The engine emission levels are a function of the engine
timing, air/fuel ratio, and the specific fuel gas composition. WMNA projects permit air
emissions based on the EPA New Source Performance Standards (NSPS) for stationary
equipment that limit any one pollutant to 250 tons per year. For reciprocating engines, the
limiting pollutant is NOX. For most areas, this limits the number of engines at a facility to
four high pressure engines or three low pressure engines in order to stay below 250 tons
per year NOX. Beyond these limits, the permit application would require a fairly elaborate,
extensive, and often expensive, review under the Prevention of Significant Deterioration (PSD)
program. For this reason, planned facilities with enough available gas to support more than
four engines often decide to use combustion turbine technology, which emits much less NOX
and slightly less carbon monoxide (CO) at comparable horsepower than reciprocating
engines, rather than submit to the PSD review.
Fuel Gas Compressor Systems
The required fuel pressure at the Centaur turbine is typically 175 psig which is delivered
jsually by a dedicated fuel gas compressor (FGC) system. Most Centaur FGC's are rated
or 1800 standard cubic feet per minute (SCFM) at an inlet gas pressure of 6 inches of
nercury vacuum and a final discharge pressure of 185 psig. Except for the first four
-.ystems built, WMNA's Centaur FGC's utilize a two stage compression process using a
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positive displacement, rotary lobe blower first stage and an oil injected, screw type
compressor second stage. Prior to the plant, each gas collection system has an
underground liquid knockout tank to collect the major portion of liquids that are carried off
the landfill with the gas. Inside the plant, an inlet scrubber vessel, primarily a large vessel for
velocity reduction with a stainless steel wire mesh pad, removes additional liquids and
paniculate (dirt and debris). After each stage of compression, the gas is cooled in an aerial
heat exchanger to further remove moisture from the gas. Injected oil and gas are
separated after the second compression stage and prior to cooling. Liquids and paniculate
are removed again from the gas in a gas filter after cooling. Prior to exiting the FGC
system, the gas is reheated in a gas-to-gas heat exchanger by hot gas exiting the oil/gas
separator vessel. This raises the gas temperature 20 to 40°F above the gas dew point to
ensure that no liquids form prior to reaching the turbine. Finally, a final gas filter (0.3 micron
absolute) mounted just prior to the turbine/generator acts as the last barrier for
paniculate and water remaining in the gas. No additional gas treatment other than
compression, cooling, filtration, and reheating are performed.
Of the twenty-five Centaur FGC systems, seventeen use Sutorbilt blowers for the first stage
of compression and Howden compressors for the second. Another three FGC's use Roots
blowers for the first stage, and again, Howden compressors for the second stage. The
most recent FGC system installed for a Centaur turbine utilizes a Roots blower first stage
and a Dresser-Rand TVC, an oil injected, screw type compressor, for the second stage.
Additionally, WMNA's first four Centaur turbine power systems used a Roots blower for the
first stage of compression, and Hall reciprocating compressors for second and third stages
of gas compression, yielding the same rated discharge pressure and flow.
Reciprocating engine FGC systems are very similar to the turbine fuel compressors in design
philosophy, however, the engines require much less fuel at much lower delivered gas
pressures. Because of this/most engine/generator facilities utilize a single FGC system for all
of the engines installed at the site. For the "high pressure" engines, two different systems
are in use: (1) a two stage, rotary lobe Roots blower system rated for 400 SCFM at one
site, and (2) a single stage system with two Dresser-Rand TVC oil injected, screw
compressors in parallel rated for 1600 SCFM at two sites. The first system supplies gas for
a single 3516 engine, whereas the second supplies fuel gas for four 3516's. Both deliver the
gas at 35 psig to the engine and utilize the same compression/cooling/reheat philosophy as
the turbine FGC's. In 1991, however, the engine facilities did not utilize the final gas, 0.3
micron filter as the turbines do.
The "low pressure" engine plants also use a single FGC system for all of the installed engines.
However, because the required fuel pressure is only 2 psig, a single stage rotary lobe blower
is used. The single blower FGC system takes the gas from a vacuum and boosts it to
approximately 7 psig, cools, filters and reheats the gas and delivers it to the engines at 2
psig. All of the "low pressure" FGC systems have been built using Roots blowers. Vessel and
cooler sizes have been adjusted to two standard systems rated at 800 and 1200 SCFM.
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The 800 SCFM system can supply fuel gas for 2 to 3 engines at full load depending on the
BTU value of the gas. The 1200 SCFM system is sized for 3 to 4 engine facilities.
Plant Operations
In budgeting operations at WMNA's LFG recovery plants, two operating criteria are reviewed
annually to predict plant output for the approaching year: (1) equipment on-line time, and
(2) plant capacity. Plants are required to anticipate equipment routine maintenance,
operational problems, major overhauls and gas well field changes in order to estimate
energy delivered to the utility or gas sales to the end customer. These energy delivery
projections are used to budget revenue. In addition, each plant must submit a budget for
expenses required to operate and maintain the facility.
Equipment on-line time is a determination of equipment availability taking into account
equipment maintenance, potential operating problems, and any planned changes to the
system (i.e. installation of a new generating unit that would require downtime to make the
electrical tie-in). WMNA's equipment is typically budgeted to operate ninety-three percent
(93%) of the time. This 7% of equipment in operation, or downtime, includes all equipment
and facility maintenance, and all potential operating problems. To reiterate, 93% on-line is
0£l the budgeted plant availability, but is a budgeted time for each individual turbine or
engine/generator to be producing power. For facilities in their first year of operation, the
expected on-line time is reduced to 85% to allow for completion of start-up related
problems or changes, and also to allow the plant operator to build experience and
confidence in his job without undo pressure.
Even though the budgeted on-line times are 93%, many of WMNA's facilities have exhibited
that better performance is possible. Nine of WMNA's nineteen facilities in operation for the
full year in 1991 operated above the budgeted level. One facility, the DFW turbine/generator
plant in Lewisville, TX, operated at an equipment on-line time of 98.5% for the year. Overall,
turbine/generator equipment averaged 93.9% on-line time excluding well field/gas collection
system problems, and 86.0% including them. Engine/generator equipment for 1991
averaged 95.5% and 89.6% on-line times excluding and including, LFG well field problems,
respectively.
Budgeted plant capacity, as well as plant on-line time to some degree, is in direct relationship
to the volume of LFG fuel that can be recovered. LFG, as the fuel, is the singular factor that
determines the power output level that the plant can sustain. For facilities with power
capacity greater than the available gas volume, this results in operating the generating
equipment at some partial load below full rating. If the gas shortage is even more severe,
shutting down individual generating units may be required. This must be considered when
budgeting plant performance and equipment on-line time.
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For facilities with LFG supplies that are ample enough for full plant output, budgeting power
output, and therefore energy sales, should be more predictable. For reciprocating engine
driven generators, power output is primarily fixed by the rating of the equipment, and
ambient conditions play little role affecting capacity. However, because the first step in the
thermodynamic process of a gas turbine is to compress the combustion air prior to ignition,
cooler air which is more dense and less humid requires less compression work to be
performed by the turbine, and allows more work to be converted into electrical energy
output. Therefore, ambient temperatures affect gas turbine driven generator outputs
dramatically from season to season, and from geographical location to location. In summer,
with ambient temperatures averaging 80 to 90°F in the daytime, and 60 to 70°F at
nighttime, average expected Centaur turbine power output would be 2800 to 2900 kW. In
winter with much colder ambient temperatures, WMNA has experienced Centaur turbine
output improvements by as much as 600 kW. At the DFW plant in Texas, and an inlet air
evaporative cooler is used in late Spring and Summer to lower inlet air temperatures to
60°F. (Because of the principles evaporative coolers work under, dry, warm air conditions
create the most efficient conditions for their use.) Budgeted power capacities assume
average climatic conditions for each facility, however, nature does not operate on averages.
As a result, weather conditions can affect plant performance, but over the year, the
conditions average out.
•
Other operator controlled factors may also improve plant performance. On average WMNA
knows that the plant parasitic loss, that is the power to operate the FGC and facility lights,
heat, etc., for a turbine/generator facility is about 17%, for "high pressure"
engine/generator facilities, about 13%, and for "low pressure" engine/generator facilities,
less than 10%. Some turbine facilities with multiple generating units and FGC's, have
manifolded the FGC systems together with cross-over valves. This allows the facility in
conditions of LFG shortages to operate all generating units from fewer FGC's, thus reducing
parasitic load. Additionally, the cross-over valves allow maintenance on one FGC system,
typically required more often than turbine maintenance, to be performed while operating the
associated turbine off of excess capacity from the other FGC systems. At other facilities
that operate under day to night on-peak and off-peak utility rate changes, lost electric sales
due to planned maintenance outages can be minimized by performing work at night when
rates are lower. Each of these operational variations improves plant net performance and
maximizes energy output sales to the utility.
OPERATIONAL PROBLEMS
Since WMNA projects began operating in 1986, much experience has been gained through
experience regarding problems with operating and maintaining LFG recovery equipment.
Three (3) operational problems that have been encountered by WMNA, two which remain a
continual struggle, greatly affect plant capacity, equipment maintenance costs, and
equipment on-line time.
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Fuel Gas Compressor Oil Carryover
In April 1988, WMNA learned through experience, the effects of oil and liquid carryover into a
turbine engine. It was discovered after a turbine failed at the Omega Hills gas recovery
plant in Menomonee Falls, Wl, that a black, carbon buildup was developing at the turbine fuel
injector tips. The turbine had 21,000 hours of operation and had been inspected by Solar
field service personnel four months previously. It was determined that the cause of failure
had been carbon deposits at one injector tip sufficient enough to divert the fuel gas path to
the area between the inner combustion chamber and the outer turbine liner. This diverted
gas acted as a torch and eventually burned a hole in the side of the turbine. As a result of
the failure, precautionary measures, primarily removal, inspection and cleaning of all fuel
injectors at quarterly maintenance intervals, were established. This maintenance, added
significant equipment downtime which in turn reduced electric sales revenues.
An equipment evaluation at Omega Hills was also made. It was determined that the FGC
process, which utilized reciprocating compressors with oil drip lubricators, was at fault and
that modifications could be made without changing the major system components which
would improve liquid and oil removal from the gas prior to reaching the turbine.
Before the new modifications could be thoroughly tested, another turbine experienced a
failure from the same cause. This turbine, located at the GROWS facility outside Philadelphia.
failed with a little more than 17,000 hours of operation and incorporated a FGC system with
an oil injected, rotary screw compressor, rather than a reciprocating compressor. Turbine
fuel injectors had been inspected and cleaned quarterly; this indicated that sufficient carbon
deposits to cause a failure could accumulate faster than the operator was removing them.
By the time a complete failure analysis could be performed, the results of the FGC changes
at Omega Hills were apparent; the oil and liquid carryover to the turbine had been reduced
almost 100%. The principle component achieving these results was a final fuel gas filter
manufactured by Pall Well, that was installed in the turbine room just prior to where the gas
enters the fuel control system on the turbine skid. It was immediately decided to retrofit all
of the existing turbine systems with the filter to prevent future turbine failures.
Most of the filters have now been in service at least one year and all indications are that
they are performing very well. Turbine fuel injectors remain so clean that only semiannual
spot checks are made for fuel injector carbon buildup. The final analysis is that WMNA
turbine facilities have removed a potential failure mode and reduced the amount of
necessary maintenance downtime.
Reciprocating Engine Ash Deposits
Through the experience of Caterpillar and WMNA, the choice of lubricating oil for the CAT
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3516 landfill gas engines has been primarily standardized to a modified natural gas engine
oil. The oil has extra additives to prevent attack from corrosive chlorine, fluorine and sulphur
bearing compounds found within the landfill gas fuel. An oil consisting of a total sulphated
ash content of approximately 1% and with a nominal total base number (IBM) of 10 has
been found to be ideal for combating engine acids formed by these compounds. Oils with
higher TBN and ash content will maintain their acid neutralizing effects longer and thus
lengthen oil change intervals. However, experience has shown that excessive ash in high TBN
oils can have a detrimental effect to the cylinder heads over time. Oils with low TBN and
ash, similar to standard natural gas engine oils, tend to be depleted of their neutralizing
agents within several hundred hours and therefore make oil changes frequent and cost
prohibitive. Most WMNA engines are on 750 hour oil change intervals, but are modified
depending on the makeup of the landfill gas fuel. Oil analysis for metals, TBN, oxidation,
nitration, viscosity, and water content taken at several intervals between oil changes also
benefit the plant operators in deciding when to change oil and filters.
Even the 1% total sulphated ash oil that is in current use leaves hard, white deposits on the
cylinder heads, piston crowns, inside the exhaust manifold and on turbocharger wheels and
housings. The deposit material has been tested and determined to be a combination of oil
additives and silica. The oil is apparently "blowby* getting past the piston rings and/or
through wear in the intake and exhaust valve guides. The silica contribution to the formation
of the deposits remains in debate. Some people are convinced that the silica is carried with
the LFG from the landfill in gaseous form, and thus cannot be filter out. Others argue that
the silica is brought in with the intake combustion air. However, oil analysis of off road
vehicles in much worse service environments compared to oil analysis of stationary LFG
engines inside an enclosed building do not support the air intake claim.
Many theories have been proposed on how best to reduce the deposit buildup. Caterpillar
believes that dehydration of the LFG fuel by refrigeration will remove the silica from the gas,
and thereby reduce the deposit material strictly to oil ash which is common for all natural
gas engines. WMNA has installed a gas dehydration unit at one facility which appears to
have reduced maintenance levels. WMNA has recently installed a Pall Well filter at one engine
site similar to the turbine fuel gas filters. Not enough operating experience has occurred to
make even a preliminary judgement of the filter's performance. WMNA, in conjunction with
Caterpillar recommendations, has also tried water injection into the engine cylinders to
steam clean the deposits from the heads and pistons; preliminary conclusions suggest that
this might have some merit if starting with a new engine with minimal oil consumption and no
initial deposits. In a final case, WMNA has had a complete cylinder head and piston crown
coated with a ceramic material that prevents the deposits from adhering to the metal; to
date, this option seems to offer the most promise, however, the cost of the coating might
prove excessive for the benefit derived.
In the end, it appears that the deposits accelerate the formation of even greater deposits.
As the engine breaks in and oil begins to blowby the piston rings, and wear occurs in the
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valve guides, silica begins to react with the oil to form deposits on the piston crown and
head. As the deposits increase, areas of deposits begin to flake off and exacerbate wear
between the cylinder liner and piston rings, and between the valve stems and guides. As
more wear occurs, more oil enters the piston chamber and more deposits are formed, which
in time create more wear; the cycle soon becomes circular and deposits theoretically
increase exponentially.
Current maintenance schedules call for top end overhauls at 8,000 to 9,000 hours of
operation. Most cylinder heads, when removed at this time, are covered by deposits up to
1/8 inch thick. The cylinder heads are typically replaced with rebuilt heads, however deposits
from the top of the piston must be removed. The deposits are usually so hard that only a
hand-held grinding wheel can remove them in a timely manner.
Prior to planned maintenance, several operating problems can result from the deposits.
Pieces of flaked-off deposits get lodged between exhaust valve faces and seats and prevent
full closure of the valves; this small opening provides a path for hot gases and flames to
escape during the combustion stroke and causes concentrated heat stress, or "guttering*,
to occur. Deposits on piston crowns as small as 1/8 inch can change the effective
compression ratio of a cylinder and cause detonation or pre-firing; this can have many
negative mechanical effects on the engine. Lastly, turbocharger wheels with several
thousand hours of operation typically exhibit grinding marks on the blades from contacting
deposits on the housing. If grinding is severe, the turbo wheel may become unbalanced and
wipe out the entire wheel and/or the bearings. All of these resultants of the ash/silica
deposit buildup cause increased downtime, equipment maintenance costs and lost electric
revenues. WMNA continues to search for the answer to these problems.
Gae Well field/Collection Systems
As mentioned previously, LFG well field, collection system, and gas shortfall problems are the
primary factors that determine the relative success of the project. However, because of the
uncertainty of predicting future landfill operations and volumes, the complexity of designing
gas well fields and collection systems, and the difficulty in hiring, educating, and retaining
proficient well field technicians, many times this factor is the most difficult to control. All of
the well field/gas collection system problems in 1991 combined to total nearly 100% of
WMNA plant output reductions and 56% of all equipment downtime.
Many landfills have installed gas control systems and flares to prevent LFG migration from
:he landfill property. Under these circumstances, collection of nearly all of the gas is
Daramount to succeeding with the task. Consequently, the "quality" of the gas collected is
)f minimal importance to the operation of the flare.
:or LFG recovery however, the quality of the gas, that is the content of the primary
onstituents i.e. methane, carbon dioxide, nitrogen, and oxygen, is of utmost importance to
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prevent short term equipment malfunctions, to promote long term equipment life, and finally,
to ensure that LFG generation will continue and be productive for many years in the future.
WMNA LFG well field systems are typically tuned" to maintain 53 to 54% methane in the
total gas "quality" at the plant. Lower methane concentrations give rise to higher carbon
dioxide, nitrogen and oxygen levels. Oxygen in the plant can create risks due to potential
explosions if in high enough quantities, and can accelerate oxidation of the equipment from
corrosive attack. Rise of carbon dioxide, nitrogen and oxygen levels can indicate breaks in
the landfill cover material, breaks in the gas collection system, or more importantly, stress
of the bacterial microorganisms within the landfill due to air intrusion. If excessive, air
intrusion into the landfill can slow or stagnate the gas generating bacteria for many years
before they can regenerate and begin producing usable LFG again. Air intrusion in its worst
extreme can also create underground oxidation, a landfill fire.
Many LFG recovery and power plants are installed to replace or substitute gas control flare
systems. Certain assumptions are made during the project development of the power
facility regarding plant output over the life of the pending utility contract, usually for ten
years. However, LFG fuel quality or collection system limitations may not allow the power
plant equipment to extract the necessary fuel to operate the plant at the expected level. If
so, economic expectations of the facility will not be met. If ample fuel can be extracted from
the landfill to operate the facility at maximum output, the gas recovery plant may not be
performing its function to collect all of the gas being generated and thereby controlling LFG
migration.
At one WMNA location it is necessary to operate both turbine/generator units at a partial
load to control gas migration. However, because of the inefficiency of the turbines operating
below full load and design flow restrictions of the FGC systems which require operating both
FGC's and therefore create higher plant parasitic loads, plant output levels are less than
could be achieved using only one turbine/generator. As a result, plant electric sales surfer to
maintain gas migration control.
Determining the capacity of LFG electric generation facilities is a delicate cooperative effort
between estimating the volume of generated and recoverable LFG, designing the gas well field
and collection system, and sizing the eventual LFG fueled power facility and equipment. All of
these factors will affect the operation and performance of the power plant once completed.
Unfortunately, each of these three factors may be considered independently; 1) by a gas
testing or assessment group that estimates the volume of gas being generated, 2) by the
collection system design engineer that places the locations of the recovery wells on the site
plan and sizes the collection system header, and 3) by the project manager who decides the
size of the facility and what power generating equipment will be installed. If these parties do
not communicate effectively in the early stages of the project, the results at times have been
a landfill with off-site gas migration problems, a gas collection system that is supplying
100% of its design flow, and a power facility operating below the expected plant output
capacity; no one benefits in this scenario.
M-15
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Another well field and collection system problem that affects LFG recovery is the continual
battle of installing and maintaining gas wells and collection systems in active landfill areas.
After gas wells and collection header pipe are installed, many landfills are permitted vertical
expansions that allow more refuse to be deposited on top of the existing collection system.
Wells can be extended, but only with solid pipe, thus reducing the effective zone of the well to
the lower portion of the landfill. Collection header pipe, however, usually gets buried below
twenty, thirty, even forty feet of new trash. Pipe breaks or collapses due to settling of the
new refuse usually dictate new header systems to be installed because the total depth below
the surface is prohibitive. Other times, a section of landfill with gas wells that has been
inactive for a time will be reopened; the area around the well will be exposed creating
potential for air intrusion. As a result of these problems, power plant equipment may be
required to shutdown or reduce output levels in order to perform collection pipe repairs or
prevent pulling oxygen into the landfill.
Landfill gas, arguably, is a potential hazard, and less arguably, is a nuisance odor. LFQ has
also become a fuel for electric power generation. However, LFG recovery must be able to
co-exist with landfill operations, control gas emissions into the atmosphere, and provide
usable fuel for power generation. At WMNA facilities, as well as most other gas recovery
operations, power generation sales account for only a fraction of the total landfill revenues.
In addition, odor and gas migration control may be part of operating permit requirements,
and will definitely affect public relation efforts. As a result, landfill operations and gas
migration control will not be compromised to benefit power generation.
Gas well field, collection system and gas shortfall problems pose the greatest challenge to
LFG recovery power generating facilities with regard to equipment performance and overall
project success, as well as achieving the dual purpose of maintaining gas migration control
from the landfill site. Gas recovery facilities will always walk a fine line between being
oversized for the volume of available LFG and operating below full output capacity, and being
undersized and not able to control odors and gas migration from the landfill property. A
delicate balance between these two goals must continually exist.
M.ic
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APPENDIX N
1-95 LANDFILL GAS TO ELECTRICITY PROJECT
UTILIZING CATERPILLAR 3516 ENGINES1
Bill Owen
Michigan Cogeneration Systems
San Diego, California
Introduction and General Overview
The I-95 Landfill is operated by the County of Fairfax, Virginia and is
located approximately 25 miles south of the nation's capital. The facility
is owned and operated by Michigan Cogeneration Systems Inc. (MCS) of
Novi, Michigan.
The facility began commercial operations in January 1992 and consists of
four (4) Caterpillar 3516 spark ignited engines, each capable of producing
800 Kw. The facility utilizes landfill gas (LFG) as its only fuel source and
produces 3200 Kw gross. After internal parasitic losses the facility nets
approximately 3050 Kw for export to the local utility, Virginia Power.
The facility is operated and maintained by one full time employee of MCS.
History of Project
Since the mid 1980's the County of Fairfax had attempted to work with
several developers in an attempt to develop a LFG to energy project at the
I-95 Landfill.
In February 1990 the County issued an RFP from which MCS was selected
as the most qualified bidder. In December of 1990 MCS and the County
executed an agreement giving MCS the gas rights to the landfill. MCS
began engineering the project in late February and synchronized with the
utility in late November, approximately 10 months. The month of
December was used to wring out the system, and MCS went into
commercial operations in January 1, 1992 selling firm capacity and
energy to Virginia Power under a 20 year contract at an average rate of
5.2 c/kWh. The cost of the project was approximately $3,200,000.
iThis site was featured on the landfill gas tours as part of the Solid
Waste Association of North America's fifteenth annual Landfill Gas
Symposium held in Arlington, Virginia on March 24-26, 1992.
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Landfill and Landfill Gas System
The 1-95 Landfill is an active landfill which receives nearly 5,500 tons of
refuse per day. The landfill is adjacent to Route 1 and Interstate 95 and
is north of the Occoquan River. The landfill is titled in the name of the
United States with the District of Columbia as the "beneficial owner".
Fairfax County runs the landfill through a Memorandum of Understanding
between the two governments.
The landfill was opened in 1972. The landfill has since expanded to 290
acres with nearly 17.5 million tons of refuse in place.
An Energy Resource Recovery Facility has been constructed at the site and
is currently burning 3,000 tons per day of the refuse stream. The plant
currently produces 70 Mw of power for sale to Virginia Power.
The County operates a perimeter collection system consisting of
approximately 50 wells. This system is operated to provide off-site
landfill gas migration protection and has extraction wells both within and
outside the refuse.
The main collection system is operated and maintained by the County
under contract to MCS. The main collection system currently consists of
15 vertical wells covering approximately 22 acres. The wells vary in
depth from 50 to 100 ft. Since commercial operation began (1/1/92) the
collection system has provided 100% of the power generation systems
needs. The power generation station consumes 1150 cfm of landfill gas.
For the first three months of operation the gas continues to maintain its
high quality at approximately 55-58% methane. As part of the County's
closure plan for a portion of the landfill, an additional 65 vertical wells
covering 70 acres will be installed later this year. MCS intends to use the
additional gas from these wells in a second 3 MW facility.
Gas Preprocessing and Energy Plant Equipment
MCS's spent considerable time examining the other landfill gas to
electricity projects in an effort to establish a clear design philosophy
from which we would build our plant The result of our investigation was
that many of the projects which were encountering problems paid little or
no attention to the proper selection of equipment for the application. The
N-2
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utilization of used outdated equipment for the sake of capital savings is
the fundamental reason for project problems at a variety of sites.
Based on the technical review of the projects visited by MCS coupled with
MCS's own operational experience from our 6.6 MW landfill gas recovery
project in Michigan, MCS developed a design philosophy for the project.
MCS's philosophy was to utilize equipment which was of proven design and
which was specifically adapted for use on landfill gas. The following is
the culmination of our effort.
Landfill Gas Handling and Preprocessing
The main consideration relative to the gas handling system was to provide
the Caterpillar engines gas at a minimum of 2 psi, filtered, and free of
liquids. This meant that other than providing good filtering of the gas to
remove silica and participates, that no "processing" of the gas was
required. A block diagram describing the system is provided for ease of
reference. The gas first enters a primary filter separator which removes
all free liquids as well as particulates down to 1.0 microns. The gas then
enters the 100 hp blower at approximately 90 °F and is compressed to 6
psig. The gas is then cooled in a forced air gas cooler. Any liquids which
may drop out during the cooling process are removed by a trap and
collected in a condensate storage tank. The gas then passes through a
temperature control valve where its temperature is maintained at a
preset level for emissions control. The gas then enters the final gas
coalescing filter where any free liquids are once again removed as well as
particulates down to 0.3 microns. The gas is then transported by a
stainless steel header to each of the four Cat engines. Due to corrosion
concerns, all gas piping in the plant is stainless steel.
Engines
The engines selected for the project were the Caterpillar 3516 spark
ignited engines. The engines were selected based on their proven
operating history on landfill gas and their low gas pressure requirement
of only 2 psig. The operating history from sites utilizing the 3516
engines showed that the engines were exceeding Caterpillar's major
maintenance intervals for top end overhauls. The engines were getting
between 12,000 - 14,000 hours between top end overhauls. The engines
were also operating at greater than 90% availability for each of the sites
reviewed. The low gas fuel pressure of 2 psig was an additional economic
benefit since comparable engines require 30-40 psig fuel pressure which
N-3
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Gas from
Landfill
Primary
Filter
n
Drains
Condensate Tank
Blower
Recycle
Valve
Gas Temperature
Control Vafve
Gas Cooler
I N>ain
Final
Fitter
• To Engines
Drains
1-95 Process Flow
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creates greater system complexity and greater parasitic losses due to gas
compression.
The Caterpillar 3516 has a nameplate rating of 1138 hp/unit with a
corresponding output of 800 kW at the generator terminals.
The engines were approved by the local air pollution control district who
generally supported the concept of landfill gas utilization.
Performance/Availability
The overall plant performance has been exceptional to date and has far
exceeded our initial target of 90% availability. The first two months of
operation have produced overall system availabilities of 93% and 98% for
January and February. The engines have been exporting between 3050-
3100 kW net.
The maintenance on the engines is being performed by MCS according to
Cat's recommended maintenance procedures and intervals. Oil change
intervals are determined by measuring the TBN level in the oil.
Caterpillar recommends changing the oil when the TBN level reaches half
of its original level. Oil changes have been performed at between 650-
750 hours per engine for the first two months.
Environmental/Emissions
The engines were permitted by the Virginia Department of Air Pollution
Control. The engines are permitted for the following limits:
rCK 2.0 grams/hp hr
00 2.04 grams/hp hr
NMHC 0.461 grams/hp hr
in order to maintain the engines emissions at a constant level, it is
necessary to control the combustion air to fuel ratio to the engines at a
constant level. By maintaining the air to fuel ratio at a fixed relationship
the engines always see the same fuel mixture and therefore produce the
same emissions. This is accomplished by maintaining both the air inlet
temperature and the gas inlet temperature to the engine at constant
preset levels. These preset temperatures are maintained by use of
temperature control valves. By controlling these parameters, the air to
fuel ratio and therefore the engine emissions remain constant regardless
of ambient temperature changes.
N-5
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Facility Expansion
MCS is planning to expand the facility to produce an additional 3 MW of
power. The development work for phase II is currently underway with the
second plant scheduled for operations January 1993. Based on the
operating history of the initial 15 wells, MCS is very confident that the
additional 65 wells planned by the will provide more than enough fuel for
the second phase.
Discussion
MCS believes that the formula for success for landfill gas to electricity
projects involves two key factors or ingredients.
The first is the proper sizing of the plant relative to the amount of
landfill gas the landfill is expected to produce. A major problem for many
sites was the oversizing of their facilities relative to the actual landfill
gas volumes recovered. MCS has attempted to avoid this pitfall by using
actual gas recovery rates from the collection system in lieu of theoretical
calculations. The use of theoretical gas projections without any
supporting data from actual well tests is very risky.
The second is the selection of the proper equipment and material for the
application. This included the Caterpillar 3516 engine, stainless steel gas
piping, and high efficiency gas filters. By utilizing these proven types of
engineering equipment, it significantly improves the longterm success of
the project while reducing annual maintenance costs.
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TECHNICAL REPORT DATA
ffteae read Imttruetiotu on the reverse before com/tie tint)
1. REPORT NO. 2.
EPA-600/R-92-116
.. TITLE AND SUBTITLE
Landfill Gas Energy Utilization: Technology Options
and Case Studies
. AUTHORIS)
Don Augenstein and John Pacey
PERFORMING ORGANIZATION NAME AND ADDRESS
EMCON Associates
San Jose. California 95131
^SPONSORING AGENCY NAME AND ADDRESS
SPA. Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park. North Carolina 27711
6. REPORT DATE
June 1992
6. PERFORMING ORGANIZATION CODE
B. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68- Dl- 0146, Task 15
13. TYPE OF REPORT AND PERIOD COVERED
Task final: 3/91-3/92
14. SPONSORING AGENCY CODE
EPA/600/13
SUPPLEMENTARY NOTES AEERL projectofficeris SusanA> Thomeloe. MailDrop63. 919/
541-2709.
The report discusses technical, environmental, and other issues associated
with using landfill gas as fuel, and presents case studies of projects in the U. S.
Illustrating some common energy uses. The full report begins by covering basic
.ssues such as gas origin, composition, and means of collection; environmental and
•egulatory background is presented. Properties of handfill gas as a fuel are review-
id; equipment that can utilize landfill gas is discussed. The report then describes
ucperience with six projects in the U. S. where landfill gas has been used for ener-
y. It also references literature on other landfill'gas energy projects of interest.
Conclusions regarding uses of landfill gas for energy are presented.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Dilution
irth Fills
ises
tels
iergy
fuse
Decomposition
Methane
Carbon Dioxide
iase to Public
b.lDENTIFIERS/OPEN ENDED TERMS
Pollution Control
Stationary Sources
Unclassified
20. SECURITY CLASS (This pagt)
Unclassified
c. COSATI Field/Group
13B 11M
13C 07C
07D 07B
21D
14G
21. NO. OF PAGES
189
22. PRICE
m 2220*1 <»-73)
N-7
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