EPA-600/R-98-021
EMERGING TECHNOLOGIES FOR THE
MANAGEMENT AND UTILIZATION OF
LANDFILL GAS
by
Stephen Roe
Joel Reisman
Randy Strait
Michiel Doom
E.H. Pechan & Associates, Inc.
2880 Sunrise Blvd., Suite 220
Rancho Cordova, CA 95742
EPA Contract No. 68-D30035
Work Assignment No. 3-109
Project Officer
Susan A. Thorneloe
Air Pollution Prevention and Control Division
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
Prepared for:
U.S. Environmental Protection Agency
Office of Research and Development
Washington, DC 20460
January 1998
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ABSTRACT
In October 1993, President Clinton released the U.S. Climate Change Action Plan, a blueprint for reducing
emissions of greenhouse gases (GHGs) in the U.S. (Clinton and Gore, 1993). The plan is designed to
reduce emissions of GHGs in the U.S. to 1990 levels by the year 2000 in a cost-effective manner. For
landfills, the plan includes actions for increasing the stringency of landfill regulations to control emissions,
an outreach program, and expansion of research and development (R&D) for methane (CH4) recovery from
landfills.
The U.S. Environmental Protection Agency (EPA) finalized regulations for new landfills, and guidelines for
existing landfills, to reduce landfill emissions on March 12, 1996 (61 FR 49, 1996). However, the
regulations do not require the utilization of landfill gas (LFG) to produce energy or other products. The
EPA's Air Pollution Prevention and Control Division (APPCD) is conducting ongoing research to provide
information on options for managing and utilizing LFG as a means of assisting landfill owners/operators that
may be affected by the regulations. This report presents information on emerging technologies that are
currently ready for commercialization (Tier 1), undergoing R&D [e.g., field- or bench-scale demonstrations
(Tier 2)], or are being considered as potentially applicable (Tier 3) for: 1) the utilization of landfill-derived CH 4
and carbon dioxide (COj); or 2) the management of landfills to reduce emissions of CH4 and other pollutants.
The technologies that are considered to be Tier 1 technologies include (1) phosphoric acid fuel cells
(PAFCs), (2) conversion of CH4from LFG to compressed landfill gas (CLG) for vehicle fuel or other uses,
and (3) use of CH4 from LFG as a fuel for landfill leachate evaporation. International Fuel Cells Corporation
(IFC) was awarded a contract by EPA to demonstrate energy recovery from LFG using a commercial PAFC.
Major advantages of this technology are its high energy efficiency, minimal by-product emissions, and
minimal labor and maintenance. The technical feasibility of CLG production for use as vehicle fuel has been
commercially demonstrated using different processes in the U.S. and abroad by the Los Angeles County
Sanitation Districts (LACSDs) and a French firm (the SITA Group). The economic feasibility of the
technologies employed in the U.S. has hinged on the availability of a sufficient user vehicle fleet. LFG is
also being used in the U.S. to evaporate landfill leachate and LFG condensate.
Technologies that are undergoing R&D and presented here at the Tier 2 level include operation of landfills
as either anaerobic or aerobic bioreactors, production of methanol from LFG, production of CO, from LFG,
and use of LFG to provide heat and CO2to greenhouses. Operation of landfills as bioreactors is considered
to be LFG management technologies, although energy production can also be enhanced during operation
of landfills as anaerobic bioreactors. The overall objective of both bioreactor approaches is to enhance
waste degradation to stabilize the waste over a much shorter time-frame.
A major advantage of methanol production (as well as CLG production) is that LFG could be utilized as a
resource to produce clean vehicle fuels that provide significantly lower emissions relative to gasoline and
diesel fuels. At the same time, the air quality and human health impacts associated with flaring LFG are
minimized. Technologies are developing to produce high-purity liquid CO2 and liquefied landfill gas (LLG)
from raw LFG. This technology offers a unique opportunity for controlling both CH 4and CO 2from LFG to
produce commercial products. LFG is also being used at sites in the U.S. and Canada to produce heat in
commercial greenhouses. For the Canadian project, LFG is also being used to enhance CO2levels (for
optimizing plant growth) in commercial greenhouses.
Technologies that are considered as potentially applicable for LFG (Tier 3) include the Stirling and Organic
Rankine Cycle (ORC) engines. These two technologies could potentially use waste heat from flares used
to control landfills to generate mechanical energy. However, they have not yet undergone field
demonstration at a landfill to determine if they are technically and economically feasible.
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TABLE OF CONTENTS
ABSTRACT ii
LIST OF TABLES v
LIST OF FIGURES vi
ACKNOWLEDGMENTS vii
ABBREVIATIONS viii
SYMBOLS x
1.0 INTRODUCTION 1
1.1 Overview of the Report 2
1.2 Incentives for LFG Utilization Projects 3
1.2.1 Tax Incentives 3
1.2.2 Other Incentives 3
1.2.3 State Incentives 4
2.0 COMMERCIALLY AVAILABLE (TIER 1) TECHNOLOGIES 5
2.1 Phosphoric Acid Fuel Cells 5
2.1.1 Introduction and General Overview 5
2.1.2 EPA's LFG FC Project 6
2.2 Production of CLG for Vehicle Fuel 11
2.2.1 Introduction and General Overview 11
2.2.2 Puente Hills Landfill, Los Angeles, California 12
2.2.3 Tork Landfill, Wisconsin Rapids, Wl 22
2.2.4 Sonzay Landfill, Tours, France 23
2.3 Leachate Evaporation 25
2.3.1 Introduction and General Overview 25
2.3.2 LES and Technair System 25
2.3.3 Vaporator System 30
(Continued)
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TABLE OF CONTENTS (Cont.)
3.0 TECHNOLOGIES UNDER R&D (TIER 2) 32
3.1 Operation of Landfills as Anaerobic Bioreactors 33
3.1.1 Introduction and General Overview 33
3.1.2 Yolo County Central Landfill, California 33
3.1.3 Emissions and Costs 38
3.2 Operation of Landfills as Aerobic Bioreactors 39
3.2.1 Introduction and General Overview 39
3.2.2 Baker Place Road Landfill, Columbia County, Georgia 40
3.2.3 Emissions and Costs 41
3.3 Production of Methanol from LFG 42
3.3.1 Introduction and General Overview 42
3.3.2 Emissions and Costs 44
3.4 Production of Commercial CO2from LFG 45
3.4.1 Introduction and General Overview 45
3.4.2 Emissions and Costs 46
3.5 Use of LFG as a Supply of Heat and CO2for Greenhouses 46
3.5.1 General Overview 46
3.5.2 Emissions and Costs 47
4.0 POTENTIALLY APPLICABLE TECHNOLOGIES (TIER 3) 49
4.1 Stirling Cycle 49
4.1.1 History and Cycle Description 49
4.1.2 Current Usage 50
4.1.3 Potential for Use with LFG 50
4.1.4 Emissions and Costs 51
4.2 Organic Rankine Cycle Engine 51
4.2.1 History and Cycle Description 51
4.2.2 Current Usage 52
4.2.3 Potential for Use with LFG 52
4.2.4 Emissions and Costs 52
4.3 Molten Carbonate Fuel Cells 53
5.0 REFERENCES 54
IV
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LIST OF TABLES
1-1. Operational or Planned LFG Utilization Projects 1
2-1. Summary of Emissions and Removal Efficiencies for the GPU 10
2-2. Alternative CNG Fuel Specifications Compared to CLG Produced by the LACSD Project 13
2-3. Capital Costs For The CLG Production Facility 17
2-4. Estimate of Fuel Costs for CLG Production 17
2-5. Comparison of Emissions For Light-Duty Trucks and Medium-Duty Vehicles 21
2-6. Comparison of Emissions for Medium-Heavy-Duty Trucks and Heavy-Duty Trucks 22
3-1. Leachate Disposal Costs for a Case Study in Georgia 32
3-2. Enhanced Cell Moisture Balance 34
3-3. Changes in Leachate Quality for the Enhanced Cell 36
3-4. LFG Summary Data for the YCCL Demonstration Project 36
3-5. Costs for the YCCL Anaerobic Bioreactor Pilot Project 38
3-6. Air Emission Impacts for a Proposed LFG to Methanol Plant 44
3-7. Concentrations of Exhaust Constituents During LFG Combustion forCO2Enhancement 48
3-8. Concentrations of Exhaust Constituents in Diluted Make-Up Air to Greenhouse 48
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LIST OF FIGURES
2-1. Simplified Schematic of a Hydrogen-Oxygen Fuel Cell 5
2-2. Gas Processing Unit for the PAFC 8
2-3. Flow Diagram of the LACSD CLG Production Facility 14
2-4. Estimated Economies of Scale for CLG Production Facilities 18
2-5. Schematic of OWT LES 26
2-6. OWT/LES Sample Process Flow Diagram 26
2-7. OWT/Technair LES 27
2-8. Power Strategies™ Leachate Destruction System 30
3-1. Anaerobic Bioreactor Demonstration Project at YCCL 35
3-2. Cumulative LFG and CH4 Production for the Control and Anaerobic Bioreactor Cells 37
3-3. Aerobic Bioreactor System Schematic 40
3-4. LFG and Waste Temperature Measurements Obtained During the First Six Months of an Aerobic
Bioreactor Operation 41
3-5. Simplified Process Flow Diagram of a LFG to Methanol Plant 43
3-6. Flow Diagram for Converting LFG to LLG and Purified CO2 46
4-1. Stirling Engines 50
4-2. Process Flow Diagram for PETS Organic Rankine Cycle System 52
VI
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ACKNOWLEDGMENTS
This report was prepared by Stephen Roe and Joel Reisman of E.H. Pechan & Associates, Inc., Rancho
Cordova, CA and Randy Strait and Michiel Doom of E.H. Pechan & Associates, Inc., Durham, NC (M. Doom
is currently with Acurex Corporation). The work was sponsored by the U.S. Environmental Protection
Agency's Air Pollution Prevention and Control Division and Control Technology Center. The authors are
particularly grateful for the guidance provided by the EPA Project Officer, Susan Thorneloe. The authors
would also like to acknowledge the assistance of the following individuals in both the public and private
sector who provided technical data and/or provided a review of the information presented in this report:
William Beale, Sunpower, Inc., Athens, OH
William Brown, Acrion Technologies, Inc., Cleveland, OH
John Comas, Commonwealth of Massachusetts, Boston, MA
William Ernst, Mechanical Technology, Inc., Latham, NY
Lewis Goodroad, South Carolina Energy Research and Development Center, Clemson, SC
Elson Hanson, E.H. Hanson Engineering Group, Ltd., Delta, BC
Mark Hudgins, American Technologies, Inc., Aiken, SC
Steve Maguin, Los Angeles County Sanitation Districts, Whittier, CA
John Pacey, EMCON Associates, San Mateo, CA
Phillip Tracy, Gas Resources Corporation, Englewood, CO
John Trocciola, International Fuel Cells Corporation, South Wndsor, CT
Mike Walker & Larry Connor, Pacific Energy, West Plains, MO
Ed Wheless, Los Angeles County Sanitation Districts, Whittier, CA
Ramin Yazdani, Yolo County Department of Public Works and Transportation, Davis, CA
VII
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ABBREVIATIONS
AGA American Gas Association
APPCD Air Pollution Prevention and Control Division
ASE Automotive Stirling engine
ATI American Technologies, Incorporated
BOD Biological oxygen demand
GARB California Air Resources Board
CLG Compressed landfill gas
CNG Compressed natural gas
COD Chemical oxygen demand
CONEG Coalition of Northeast Governors
DOE U.S. Department of Energy
EPA U.S. Environmental Protection Agency
FC Fuel cell
GFI Gaseous fuel injection
GHG Greenhouse gas
CMC General Motors Corporation
GPU Landfill gas pretreatment unit
GRC Gas Resources Corporation
IFC International Fuel Cells Corporation
IHC International Harvester Company
LACSD Los Angeles County Sanitation Districts
LES Leachate Evaporation System
LEV Low-emission vehicle
LFG Landfill gas
LLG Liquefied landfill gas
MSW Municipal solid waste
MTBE Methyl tertiary butyl ether
MTI Mechanical Technology Incorporated
NGV Natural gas vehicle
NMHC Non-methane hydrocarbon
NMOC Non-methane organic compound
O&M Operation and maintenance
ORC Organic Rankine Cycle
OWT Organic Waste Technologies, Inc.
PAFC Phosphoric acid fuel cell
PEI Perennial Energy, Inc.
R&D Research and development
REPI Renewable Energy Production Incentives
RFC Reformulated gasoline
RIC Reciprocating internal combustion
SAE Society of Automotive Engineers
SCAQMD South Coast Air Quality Management District
STC Southeastern Technology Center
STM Stirling thermal motors
syn-gas Synthesis gas
TCLP Toxicity Characteristic Leaching Procedure
(Continued)
VIM
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ABBREVIATIONS (Cont.)
IDS Total dissolved solids
TLEV Transitional low-emission vehicle
TMI TeraMeth Industries
TOC Total organic carbon
ULEV Ultra-low-emission vehicle
VOC Volatile organic compound
YCCL Yolo County Central Landfill
IX
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SYMBOLS
Btu British thermal unit (1 Btu = 1.055 kilojoules)
°C Degrees Celsius (°F = 9/5 °C+32)
CH4 Methane
cr Chloride
CO Carbon monoxide
CO2 Carbon dioxide
°F Degrees Fahrenheit [°C = 5/9 (T-32)]
ft Foot or feet (1 ft = 0.3048 meter)
gal Gallon (1 gal = 3.785 liters)
GGE Gallons of gasoline-equivalent
gpd Gallons per day
H2 Hydrogen
HC Hydrocarbon
H20 Water
hp Horsepower [1 hp = 1.0139 horsepower (metric)]
hr Hour
H2S Hydrogen sulfide
kW Kilowatt
kWh Kilowatt-hour
L Liter (1 L = 0.2642 gallon)
Ib Pound (1 Ib = 0.4536 kilogram)
mg Milligram (1 mg = 0.0154 grain)
MMBtu Million Btu (1 MMBtu = 1.055x106 kilojoules)
MMscf Million standard cubic foot or feet (1 MMscf = 0.0283x106standard cubic meters)
MW Megawatt
MWh Megawatt-hour
NOX Nitrogen oxides
Mm3 Normal (dry standard) cubic meter (1 Nm3 = 35.31 normal cubic feet)
O2 Oxygen
PM Particulate matter
PM10 Particulate matter less than 10 micrometers in diameter
ppb Parts per billion
ppbv Parts per billion by volume
ppm Parts per million
ppmv Parts per million by volume
psi Pounds per square inch (1 psi = 0.06804 atmosphere)
scf Standard cubic foot or feet (1 scf = 0.0283 standard cubic meter)
scfd Standard cubic foot or feet per day
scfh Standard cubic foot or feet per hour
scfm Standard cubic foot or feet per minute
sg Specific gravity
SO2 Sulfur dioxide
tpd Tons per day (1 tpd = 0.9072 megagram per day)
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1.0 INTRODUCTION
In October 1993, President Clinton released the U.S. Climate Change Action Plan, a blueprint for reducing
emissions of GHGs in the U.S. (Clinton and Gore, 1993). The plan is designed to reduce emissions of
GHGs in the U.S. to 1990 levels by the year 2000 in a cost-effective manner. For landfills, the plan includes
actions for increasing the stringency of landfill regulations to control emissions, the establishment of the
Landfill Methane Outreach Program, and expansion of R&D for CH4recovery from landfills.
The EPA finalized regulations for new landfills, and guidelines for existing landfills, to reduce landfill
emissions on March 12, 1996 (61 FR 49, 1996). However, the regulations do not require the utilization of
LFG to produce energy or other products. Of the landfills expected to be constructed over the next 5 years,
about 45 are estimated to require LFG collection and control systems. For existing landfills with capacities
greater than 2.5 million megagrams, approximately 300 will be required to install collection and control
systems (Roqueta, 1997). Projects using current technologies for LFG utilization that are operational or
planned for use in the U.S. are summarized in Table 1-1.
Table 1-1. Operational or Planned LFG Utilization Projects
T . . Operational
Technology 1: .....
a* Facilities
Reciprocating Engines
Gas Turbines
Combined Cycle
Boiler/Steam Turbine
Medium Btu Fuel
High Btu/Vehicle Fuel
89
22
2
5
27
5
Construction/
Advanced
Planning
>30
4
1
1
11
5
Capacity Range of
Installed Facilities
(kW) or Equivalent
80-12,300
740- 16,500
13,600-20,500
7,000-50,000
300-17,000
800- 19,000
NOTE: kW= kilowatt, Btu = British thermal unit.
Adapted from Roqueta, 1997.
The EPA's APPCD is conducting ongoing research to provide information on options for managing and
utilizing LFG as a means of assisting landfill owners/operators that may be affected by the regulations. The
purpose of this report is to present information on emerging technologies for managing or utilizing CH4 and
CO2 from municipal solid waste (MSW) landfills. Essentially, these are technologies other than those which
have been in commercial use for at least several years. Examples of these well-established technologies
are shown in Table 1-1 and include electricity generation with reciprocating internal combustion (RIC)
engines and gas or steam turbines and production of medium British thermal unit (Btu) fuel for input to
boilers (for process or space heating).
The technologies that are presented in this report are divided into three tiers: Tier 1 technologies are those
that are considered to be commercially available in the U.S.; Tier 2 technologies are those that are currently
undergoing additional R&D, have been tested at the bench- or field-scale, and may be ready for commercial
application; and Tier 3 technologies are those that may have applicability to LFG utilization or management
based on applications with similar fuel types (e.g., natural gas). The differentiation of technologies is based
on technical demonstration of a project and is not meant to imply that a particular technology will be
economically viable (i.e., profitable) at any given site. However, at a minimum, the technologies described
in this report should help an MSW landfill owner or operator to offset the costs of controlling landfill
emissions.
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The report is not intended to represent an exhaustive review of emerging technologies for the management
or utilization of LFG, but those processes that are being demonstrated, are planned for demonstration, or
that are technically-feasible. The array of technologies presented, as well as the level of detail provided,
are limited by the information made available by the technology developers. Discussion of the emerging
technologies is based on information that was made available to EPA as of September 1997.
It is recognized that in addition to new technologies for LFG utilization and management, advancements are
being made to existing technologies (such as those shown in Table 1-1). However, information on the
improved performance and emission reduction capability is not readily available. In response to this, EPA
is establishing the Center for Technology Verification for Greenhouse Gas Emissions (the Center). Landfill
methane is to be one of the priorities of the Center. There is $2,000,000 in funding for 1997 and EPA will
make data available from technology verification studies on the performance of either existing or emerging
technologies. Additional information on the Center's program can be found at the web site:
http://www.epa.gov/etv. Future updates to the information provided in this report will include data resulting
from research carried out through the Center. Although the focus of the Center is on GHG emissions,
information obtained on emission reductions of other pollutants and energy efficiency will also be provided,
as it becomes available.
1.1 Overview of the Report
Section 2.0 of this report contains a discussion of Tier 1 technologies. These technologies have been
demonstrated at a commercial level and show promise for economic viability at various scales of application:
• Use of phosphoric acid fuel cells (PAFCs) for generating electricity and waste heat;
• Conversion of CH4 from LFG to compressed landfill gas (CLG) for vehicle fuel; and
• Utilization of CH4 from LFG to evaporate landfill leachate and LFG condensate.
Tier 2 technologies are described in Section 3.0. These technologies are currently undergoing additional
R&D and have been demonstrated either at the bench- or field-scale. Included in this group are:
• Operation of landfills as either anaerobic or aerobic bioreactors;
• Production of methanol from LFG;
• Production of commercial CO2from LFG; and
• Use of LFG for heating and CO2 enhancement in greenhouses.
Tier 3 technologies are presented in Section 4.0. These technologies are considered to be potentially
applicable for LFG management and utilization. These technologies include the Stirling and ORC engines.
For those technologies that are considered to be technically-feasible at a commercial scale (Tier 1), the
report provides an introduction and general overview of the demonstration project, a project history (of
known projects), a process description, information on performance, a discussion of air emissions and
secondary environmental impacts, and available information on project economics. For Tier 2 technologies,
an introduction and general overview of the technology is followed by a process description and information
on air emissions and costs. For the Tier 3 technologies, the report provides information on the process,
current usage, potential for use on LFG, and potential air emissions and costs.
All of the above-mentioned information for each technology is given to the extent that the developers were
able to provide such information. The development of LFG management and utilization technologies is
ongoing. Therefore, interested readers should contact the technology developers identified in each section
of the report for the most current information.
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1.2 Incentives for LFG Utilization Projects
1.2.1 Tax Incentives
There are currently two federal tax incentive programs that may apply to LFG, Tax Credit for
Producing Fuel from Nonconventional Sources, Section 29 of the Internal Revenue Code, and Renewable
Energy Production Incentives (REPI). Some states have their own tax incentive programs as well.
Section 29 - Tax Credit for Producing Fuel from Non-Conventional Sources—
Section 29 provides a tax credit for the production and sale of certain non-conventional fuels, including LFG.
Section 29 was enacted by congress in 1980 and has been extended four times, the last extension being
granted August 20,1996, as part of the Small Business Job Protection Act of 1996, however a fifth extension
appears to be unlikely (Hickman, 1997). To be eligible, a LFG facility must have had a written binding
contract by December 31,1996, and must be placed in service by June 30, 1998 (per key elements of the
fourth extension). The value of the tax credit (established April 1997) is $1.0259 per million Btu (MMBtu),
based on $5.95 per Equivalent Barrel of Energy [i.e., 42 gallons (gal) of oil equaling 5.8 MMBtu].
To qualify for the credit, the gas must be sold to an unrelated party. No tax credit is available for the
production of electricity. Facilities placed into service after January 1, 1993 may receive the tax credits on
fuel produced and sold through 2007. Facilities in service prior to 1993 may receive tax credits through
2002.
REPI—
REPI was authorized by section 1212 of the Energy Policy Act of 1992 to provide incentives to advance the
commercialization and use of electricity generating systems using renewable energy. The program provides
state-owned and non-profit electric cooperatives (who would not otherwise benefit from a tax-incentive
program) financial incentives for the production and sale of electricity using certain renewable resources,
subject to the availability of annual appropriations. Facilities must begin their initial operation between
October 1, 1993 and September 30, 2003. Qualified facilities are eligible for production payments for the
first ten fiscal years of their operation. Payments, subject to available appropriations, are based on 1.5 cents
per net kilowatt-hour (kWh) produced (1993 dollars) and are adjusted for inflation. Payments are to be made
only for "electric energy generated and sold."
Qualified renewable energy facilities include solar, wind conversion, biomass energy systems (including
LFG), and geothermal systems. However, so-called "closed-loop" biomass systems, where energy is
derived from dedicated plant crops are considered "Tier 1" facilities and are treated differently than "open-
loop" systems, such as CH4 gas collected from a landfill (classified as Tier 2 facilities). Payments are made
to Tier 1 facilities (i.e., solar, wind, geothermal, closed loop, etc.) first. If funds are available after Tier 1
facilities are paid, Tier 2 qualifying facilities, such as open-loop biomass technologies (which include LFG)
are paid with remaining funds. If there are insufficient funds to make full payments to all Tier 2 qualifying
facilities, payments are made to those facilities on a pro rata basis. This funding priority reflects the tax
treatment of new generation technologies as contained in sections 1914 and 1916 of the Energy Policy Act
of 1992. REPI incentives are viewed by developers with caution because funds are subject to annual
appropriation decisions by Congress.
1.2.2 Other Incentives
There are several other non-regulatory federal government incentives for LFG projects. EPA operates one
of the most important programs, the Landfill Methane Outreach Program, which is part of the Climate
Change Action Plan. This program assists MSW landfill owners/operators, States, Tribes, utilities, and other
federal agencies in promoting the use of LFG as an energy resource. Some of the outreach services include
providing information to increase awareness of project opportunities, and enhance the understanding of
environmental, energy, and economic benefits of LFG projects. The outreach program works with Federal
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and state regulators to streamline the regulations and permitting procedure. The program works with utilities
and energy purchasers to increase project recognition of the environmental value of energy recovery and
its energy resource benefits (EPA, 1996).
The U.S. Department of Energy (DOE) has ongoing programs to encourage the development of LFG
projects. The Climate Challenge Program is an initiative where utilities agree to achieve GHG reductions
in ways that make sense for them. Voluntary Reporting is a program in which utilities are eligible to report
methane reductions from landfill energy recovery projects.
1.2.3 State Incentives
In the past, several states have passed laws requiring utilities to pay certain qualifying facilities, such as
alternative and renewable energy facilities (including LFG facilities), more than the utilities' avoided cost for
electricity. In January 1995, the Federal Energy Regulatory Commission found that these laws violate the
Public Utility Regulatory Policies Act of 1978, which holds that a utility should not be required to pay more
than their avoided cost to any entity.
At present, many utilities' avoided costs are too low to offer revenues adequate to support an LFG to
electricity facility because the utilities do not plan to install additional generating capacity in the near term.
In addition, the current restructuring on the electric industry may result in an industry where consumers
purchase power from independent suppliers and utilities simply deliver the power. This could make the
concept of "utility avoided cost" somewhat meaningless.
Restructuring of the electric industry offers new potential markets for electricity generated from LFG and
other renewables by allowing the LFG facility to sell power directly to a consumer. Another alternative is the
sale of LFG fueled power to a power marketer that aggregates power from a variety of sources, and resells
it to the consumer. It is unclear whether LFG fueled power will be able to compete in these new markets
as restructuring is expected to reduce electricity prices. Recent surveys indicate that some consumers are
willing to pay a premium above standard electricity rates for "Green Power", but the results of these surveys
have not been tested in the marketplace. Even with limited consumer purchases of higher priced "Green
Power", state incentives will continue to be important for continued LFG utilization. Examples of state
incentives are (1) exemptions from various state taxes for LFG facility operators, (2) a requirement that
renewables comprise a minimum percentage of the power supply mix of each utility or power supplier, and
(3) financing assistance including low interest or interest-free loans from the state to the LFG facility.
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2.0 COMMERCIALLY AVAILABLE (TIER 1) TECHNOLOGIES
Information on technologies that are ready for commercial application in the U.S. is presented in this section.
The projects described cover the following technologies:
• Use of PAFCs for generating electricity and waste heat;
• Conversion of CH4 from LFG to CNG for vehicle fuel; and
• Utilization of CH4 from LFG to evaporate leachate.
All of these projects require the processing of LFG to remove contaminants and use gas cleaning
technologies that have already been developed and demonstrated. Therefore, this report does not provide
a detailed discussion of the gas cleaning technologies, unless the developer of the emerging technology has
modified an existing gas cleaning technology. Several technologies have been developed to process LFG
to remove contaminants to meet specifications for pipeline quality gas (i.e., 91 percent CH ) or for other
purposes. An excellent summary of the various gas cleaning technologies that have already been
developed is presented in an early study by EMCON Associates, CalRecovery Systems, Inc., and Gas
Recovery Systems, Inc. (1981).
2.1 Phosphoric Acid Fuel Cells
2.1.1 Introduction and General Overview
Fuel cells may be compared to large electrical batteries (with ancillary equipment, such as catalysts) which
provide a means to convert the chemical bonding energy of a chemical substance directly into electricity.
The difference between a battery and a FC is that, in a battery, all reactants are present within the battery
and are slowly being depleted during battery utilization (though they can be regenerated in rechargeable
batteries). In a FC, fresh reactants (fuel) are continuously supplied to the cell. A simple schematic of a FC
is shown in Figure 2-1. Oxygen ions (from air) pass from the cathode, through an electrolyte (which allows
passage of oxygen ions but not electrons), and combine with hydrogen ions and carbon at the anode
(derived from a hydrogen-rich fuel) to form water [as steam, (H2O)] and CO2. Fuel cells are differentiated,
in part, by the type of electrodes and electrolytes used in their construction.
Air
Cathode T
oxygen Ion
Electrolyte
Anode
2 hydrogen ions
C02+H20
Fuel
Figure 2-1. Simplified Schematic of a
Hydrogen-Oxygen FC
There are four basic types of FCs, each of which
has a different combination of performance
characteristics. One type, the PAFC, is ahead of
the others in its developmental stage and has been
demonstrated commercially on landfill gas. PAFCs
are suitable for utility distributed power use,
commercial light industrial use, and heavy vehicular
use (Arthur D. Little, Inc., 1993; Hirschenhofer et
al., 1994). The other FC types (molten carbonate,
solid oxide, and solid polymer) are in varying stages
of development and demonstration and may be
ready for the market in 10 to 20 years (Arthur D.
Little, Inc., 1993). None of these have been
demonstrated on LFG. Commercial PAFCs use
hydrogen gas or reformed methanol as fuel sources
to produce electricity. The hydrogen gas may be
bought in purified form for small scale applications,
or it may be obtained via conversion from a
hydrogen containing fuel, such as natural gas, LFG,
digester gas, or alcohols.
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Compared to traditional power generation technologies, FC technology has two distinguishing performance
characteristics:
• high electrical conversion efficiency levels (i.e., 40 to 50 percent) are maintained over a
wide range of capacity levels: traditional technologies (e.g., fossil-fuel power plants)
typically achieve efficiencies of 33 to 35 percent. Efficiencies are expected to increase to
the 50 to 60 percent range in the near future, and if the waste heat from the FC is utilized
(e.g., in a cogeneration system) overall efficiencies could exceed 85 percent (DOE, 1997a);
and
• air emissions from FC systems are extremely low: due to their efficiency, CO 2emissions
are reduced for the same amount of power produced (as compared to traditional power
sources). Also, FCs powered on natural gas have nitrogen oxide (NOX) emissions of about
0.0004 pounds per megawatt-hour (Ib/MWh) (DOE, 1997a). As a comparison, a coal-fired
power plant using staged-combustion (achieving 25 percent NOX control) and achieving a
plant heat rate of 1,035 Btu per kWh would have NOX emissions of about 6.5 Ib/MWh (Roe
et al., 1995). A highly controlled boiler (e.g., using selective catalytic reduction to achieve
another 80 percent control) would still release about 1.3 Ib/MWh.
In addition, FCs have other advantages such as low labor and maintenance requirements and minimal noise
impact. Furthermore, FC plants are inherently modular, making the technology applicable to a wide range
of landfill sizes. Power plants can be configured from 0.025 megawatts (MW) up to 50 MW. FCs also have
the advantage of fuel flexibility. The primary source of fuel for the FC is hydrogen, which could be obtained
from a number of potential backup hydrocarbon (HC) fuels (e.g., natural gas, methanol, other liquid fuels)
as long as the gas processing system is properly designed (DOE, 1997a).
The major technical consideration associated with the application of FCs to LFG projects is the gas
purification system. The major non-technical consideration associated with fuel cells in general has been
the capital cost of the technology. To further evaluate the technical and non-technical feasibility for the
application of FC technology to LFG utilization, EPA provided funding to IFC, a subsidiary of United
Technologies Company, to demonstrate energy recovery from LFG using their commercial PAFC power
plant. The following discussion summarizes the results of this successful project. It is also worth mentioning
that plans are already underway for another PAFC project at a closed New England landfill. The preliminary
plans for this project include selling the waste heat from the PAFC to an adjacent hotel (Trocciola, 1997).
2.1.2 EPA's LFG FC Project
IFC was awarded an EPA contract to demonstrate energy recovery from LFG using their PC25 commercial
PAFC. The design of the LFG energy utilization system is based on providing a modular, packaged, energy
conversion system which can operate on LFG over a wide range of compositions as typically found in the
U.S.
The system is laid out to process approximately 18,000 standard cubic feet per hour (scfh) of LFG and
incorporates the LFG collection system, landfill gas pretreatment unit (GPU), and a FC energy conversion
system. In the fuel gas pretreatment section, the raw LFG is treated to remove contaminants to a level
suitable for the FC energy conversion system. The FC energy conversion system converts the CH4 in the
treated LFG to hydrogen which serves as fuel for the FC. In the PAFC, hydrogen and oxygen from air are
used to create electricity and steam. The system is capable of recovering waste heat for nearby use;
otherwise, waste heat is discharged to the ambient air.
The PAFC research program was divided into three phases. Phase I, initiated in January 1991, was a
conceptual design, cost, and evaluation study which addressed the problems associated with LFG as the
feedstock for FC operation (Sandelli, 1992).
-------
Phase II of the program included construction and testing of the GPU to be used in the demonstration. Its
objective was to determine the effectiveness of the pretreatment system design to remove critical FC
catalyst poisons such as sulfur and halides. The section below describes the pretreatment equipment.
Phase II activities began in September 1991, and were completed in early 1994 (Trocciola and Preston,
1995).
Phase III of the program was a demonstration of the FC energy recovery concept using LFG. During this
phase, IFC installed and operated a GPU and a 200 kilowatt (kW) PAFC. The location was Penrose Station,
an existing landfill gas-to-energy facility owned by Pacific Energy in Sun Valley, California. Penrose Station
is an 8.9 MW RIC engine facility supplied with LFG from four landfills. The electricity produced by the
demonstration was sold to the electric utility grid. Phase III activities began in October 1994, and after
successful completion of the demonstration, the FC was moved to Connecticut for additional testing.
Results of the Phase III work are described below.
Additional field testing was conducted with the equipment at the Groton landfill in Connecticut beginning in
July of 1996 by IFC in conjunction with EPA and Northeast Utilities. As of May 1997, the GPU had been run
for a total of 3,166 hrs (over 29 test runs) and the FC had been run for a total of 2,350 hrs (over 15 test
runs). Additional details on this test program and system performance are given below (IFC, 1997).
Northeast Utilities (current operater of the equipment) and the town of Groton, CT have plans to operate the
FC for several years. Further, negotiations are currently ongoing to install a greenhouse on-site in order to
utilize the waste CO2 and heat from the FC (Borea, 1997).
GPU—
The fuel pretreatment system has provisions for handling a wide range of gas contaminants. Multiple
pretreatment modules can be used to accommodate diverse landfill sizes. The collection system delivers
raw LFG at approximately ambient pressure to the GPU. In the GPU, the gas is treated to remove halide
and sulfur compounds [especially hydrogen sulfide (H2S)], and non-methane organic compounds (NMOCs).
The system was designed to achieve a maximum exit level of 3 parts per million by volume (ppmv) sulfur
(as H2S) and 3 ppmv total halide [as chloride (Cl)]. A block diagram of the GPU is shown in Figure 2-2
(Spiegel et al., 1997).
The GPU first removes H^S by adsorption on a packed carbon bed (carbon impregnated with potassium
hydroxide). This bed is not regenerable, so the spent carbon must be sent off-site for regeneration or
disposed of in a landfill. Next, the system incorporates two stages of refrigerated condensation. The use
of staged condensation provides tolerance to varying concentrations of LFG constituents (e.g., NMOCs).
The first refrigeration stage [2 degrees Celsius CC)] significantly reduces the H p content and removes the
bulk of the heavier HCs from the LFG. This step provides flexibility to accommodate varying landfill
characteristics by delivering a relatively narrow cut of HCs for the downstream beds in the GPU. Inbetween
the first and second refrigeration stages, two regenerable dryer beds are used (one is in use, while the other
is being regenerated). Each bed contains both activated alumina and Davidson 3 angstrom molecular sieve.
The primary function of these regenerable beds is to remove additional Hp to prevent freezing in the
second condensation stage.
The second condensation stage occurs at 28 'C. This stage of refrigeration may condense out heavier
HCs, if they are present at high enough concentrations. In addition, this step reduces the temperature of
the next carbon bed downstream which increases its performance. The condensate from both refrigeration
stages is discharged to a condensate treatment system (no condensate was collected in the second stage
during the Penrose test program). The second refrigeration stage and the final activated carbon filter
remove the remaining HCs, including halides and organic sulfur. Two regenerable beds are used in the final
activated carbon adsorption step, as with the first, so that one can be regenerated while the other is
operating. Finally, the gas passes through a filter to remove particulate matter (PM) and is warmed indirectly
by an ambient-air finned tube heat exchanger before being fed into the unit (Spiegel et al., 1997).
-------
i two-stage low
| temperature
i condensation
regeneration gas
LFG
i
Adsorber
Cooler Condenser
(dehydration)
Desiccants
(adsorption of H20)
Low Temperature
Cooler Condenser
(condensation)
Activated Carbon
(adsorption)
Particulate Filter
H2OandHCs
HCs, including organic sulfur
and halogenated compounds
Jt
clean LFG to FC
Figure 2-2. GPU for the PAFC
The dehydration and adsorbent beds are regenerated by using clean gas from the process stream. A
portion of the treated LFG (approximately 30 percent) is heated to 288 °C with an electric heater and then
passes through the beds in the sequence shown in Figure 2-2. After exiting the beds, the spent
regeneration gas is fed into the low-NOx incinerator where it is combusted with the vaporized contaminants
from the dryer/adsorption beds.
FC power plant —
The LFG power plant consisted of a 200 kW PC25 natural gas FC manufactured by ONSI Corporation, a
cooling module (for waste heat), and an interconnection to the power grid. Field tests were conducted in
December 1994 at the Penrose site, and between July 1996 and May 1997 at the Groton site. Performance
of the FC during the field tests at Penrose and Groton is described below.
The FC is designed to produce 200 kW of net power when operated on natural gas with a heating value of
about 900 to 1,050 Btu/scf. Modifications made to the FC for the Penrose test program included a larger
fuel control valve and fuel flow venturi, a new process fuel recycle orifice, a new cathode exit orifice, a new
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redundant start fuel shut-off valve, and modifications to the control software. The LFG used during the field
test at the Penrose site had a heating value of about 440 Btu/scf. Consequently, with the available LFG
flows, a net peak power production of approximately 137 kWwas achieved and an endurance operating
level of 120 kWwas achieved during the bulk of the field test operations (Spiegel et al., 1997). At Groton,
the heating value of the LFG was approximately 560 Btu/scf and an operating level of 130 kWwas selected,
although higher power levels were achieved (IFC, 1997). Additional details on performance during the two
field tests are given below.
Performance—
During the field test at Penrose, the GPU operated for more than 2,000 hrs and purified the LFG to a level
which is more than suitable for FC use. In particular, the GPU removed the sulfur and the halide compounds
contained in the LFG to a level significantly below the specified value of 3 ppmv. The GPU removal
efficiencies for both total halide and reduced sulfur compounds were estimated to be greater than 99 percent
(Spiegel et al., 1997).
For the field program at the Penrose landfill, the GPU was operated for a total of 2,297 hrs. During this time,
the FC was operated for a total of 709 hrs on LFG. As mentioned above, an endurance level of 120 kWwas
achieved (137 kW peak). The FC efficiency was calculated to be 37.1 percent during a six-day period of
operation, and 36.5 percent during a second eight-day period which included a brief shut-down. During the
six week test program, there were a total of eight shutdowns. Four of these were due to site-related causes
(e.g., power losses, interruption of LFG flow to GPU). Three of the shutdowns were due to the GPU: two
due to refrigeration over-temperature; and one due to a loose flame sensor on the flare. The final shutdown
was due to a failure of an inverter cooling fan sensor module in the FC control system (Spiegel et al., 1997).
During the Groton test program, the longest test runs were 524 hrs and 448 hrs for the GPU and FC,
respectively. As mentioned above, the FC was operating at 130 kWin May 1997. Two operational issues
with the GPU identified during the Groton program were icing of the d-limonene coolant and problems with
the LFG compressor valves. The compressor valves were replaced and a de-icing procedure was
developed for the coolant. For the FC, the only problem encountered was the need to replace a feed H2O
pump (IFC, 1997). Since replacement of this pump, no FC operational issues had been encountered for
over 2,350 hrs of operation.
Emissions—
Table 2-1 provides a summary of available emissions data measured for the GPU during the two test
programs. At Penrose, the GPU flare had average NOX emissions of 10.4 ppmv and 3.0 ppmv for carbon
monoxide (CO). PM emissions for the flare averaged 0.03 milligrams per normal (dry standard) cubic meter
(mg/Nm3) (Spiegel et al., 1997).
Besides electrical energy, the electrochemical reactions inside the FC produce only H2O and CO2. For the
most part, emissions, such as NO,, PM, or CO, that are typically associated with combustion are not
produced. Small quantities of these emissions from the fuel processing unit where CH 4is converted to
hydrogen are emitted from the reformer natural gas burners.
As with other LFG utilization projects, a net reduction in air pollutant emissions (especially criteria pollutants
and GHGs) will occur from the avoided use of a fossil energy source that otherwise would have been
needed to produce the electricity generated by the FC. In addition to the electrical energy, the FC can
produce up to 760,000 Btu/hr of thermal energy. If this energy is utilized, additional net reductions via
avoided fossil fuel usage can be realized.
Secondary Environmental Impacts—
The non-regenerable carbon beds in the GPU used to remove sulfur compounds have to be regenerated
off- site or disposed of in a sanitary. During the tests in California, the spent carbon was tested and found
to be non-hazardous which allowed for disposal in a municipal landfill. The alternative to disposal of the
spent carbon is to regenerate it. Typically, regeneration of activated carbon is done via heating of the spent
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TABLE 2-1. Summary of Emissions and Removal Efficiencies for the GPU
Pollutant
Inlet Concentration Outlet Concentration
(ppmv) (ppmv)
Groton Penrose Groton Penrose
Removal
Efficiency3
Total Halogens (as CI")
Total Sulfur (as H2S)
Particulates
Silanes, Siloxanes
Phenol
NMOCs (as CH4)
16-45
n/a
n/a
n/a
n/a
n/a
45-65
113
n/a
<0.076
(mg/Nm3)
<0.03 ppmv
5,700 ppmv
<0.001 -
0.014
<0.002 -
0.385
n/a
n/a
n/a
n/a
<0.002 -
0.032
<0.010-
0.047
<0.5
(mg/Nm3)
n/a
n/a
13.8 ppmv
99.5
99.96
n/app
n/app
n/app
99.8
Note: n/a = not available, n/app = not applicable.
Based on information supplied by Spiegel et al., 1997 and IFC, 1997.
a Refers to results from the Penrose field test.
carbon in a high temperature kiln at temperatures capable of destroying the adsorbed organics. Although
these processes are often highly controlled, criteria pollutants, hazardous air pollutants, and GHGs are all
emitted at varying levels during the regeneration process.
In addition, the pretreatment process produces condensate containing Hp, organic sulfur, HCs, and
halogenated HCs. The GPU described above is expected to produce a condensate with a higher loading
of organics than a typical LFG processing system (i.e., due to the two stages of condensation). At Penrose,
the condensate was transferred to the existing Penrose condensate treatment system, which consisted of
an enclosed flare. Depending on the process used to treat condensate, there could be a higher potential
for emissions of organics from volatilization during treatment (since the concentrations within the condensate
are likely to be higher).
Economics—
The major non-technical consideration associated with PCs has been the capital cost of the technology. IFC,
the manufacturer of the PAFC, has guaranteed the capital cost for the new advanced power module to be
$3,000 per kW for delivery in 1995, and plans to reduce the cost to $1,500 per kW by 1998. FC costs may
be reduced with maturation of the technology and the scale advantage of increasing production. It is
expected that the next generation of LFG FCs will be up to 30 percent smaller in size compared to the first
FC that was tested.
These estimates do not include the cost of a GPU. According to IFC, the cost of pretreating LFG for use in
FCs is around $250 per kW. IFC has started a program to test a new pretreatment concept to further reduce
the pretreatment cost to approximately $100 per kW, however no comprehensive information on this
program was available at the time this report was prepared. Based on the findings of the Phase II test report
(Trocciola et al., 1995), it may be economically beneficial on future installations to eliminate the low
10
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temperature cooler and simplify the refrigeration system in exchange for slightly increasing the activated
(regenerable) carbon bed volume.
As a comparison, the capital cost of RIC engine plants (including gas pretreatment equipment) may range
from $950 to $1,250 per kW (Thorneloe, 1992). These costs are likely to be even lower as of the writing of
this report due to increased competition and maturation of the RIC technology.
2.2 Production of CLG for Vehicle Fuel
2.2.1 Introduction and General Overview
Use of CNG has been recognized for its environmental benefits because it is a cleaner burning fuel relative
to gasoline and diesel fuel (especially in regards to NOX and PM emissions). The technology for using CNG
as an alternative fuel for motor vehicles has been demonstrated for several years. In Europe and South
America, hundreds of thousands of vehicles are operated on CNG. In the U.S., the use of CNG as an
alternative to gasoline and diesel fuel has gained interest as a method for decreasing vehicle emissions
particularly in areas designated as nonattainment with the National Ambient Air Quality Standards for ozone,
CO, and PM with an aerodynamic diameter less than 10 micrometers (PM 1().
The DOE projected that the number of natural gas vehicles (NGVs) would grow about 30 percent from 1995
to 1996, and a number of CNG-powered vehicles and engines are now available from original equipment
manufacturers (DOE, 1997b). These new vehicle/engine offerings include the CNG-dedicated 1998 Honda
Civic GX sedan (available in the fourth quarter of 1997), General Motors Corporation (CMC) Sierra and
Chevrolet C-Series light-duty pickup trucks, and Cummins 5.9 B series engines (for light-, medium-, and
heavy-duty applications). In addition, Visions Helicopter Technologies, Inc. (Woodbridge, VA) recently
developed two light-utility helicopters that run on CNG.
One of the major drawbacks to using CNG in motor vehicles is that the driving range of vehicles is limited
because of fuel storage capacity constraints. Where needed, this problem has been minimized by installing
bi-fueled systems (e.g., CNG, and gasoline or diesel) on the vehicle. Another limitation has been the
availability of fuel dispensing facilities. However, the American Gas Association (AGA) reports that the
number of refueling facilities in the U.S. tripled between 1994 and 1997 (to over 1,100 in 46 states in 1997)
(AGA, 1997). Historically, because of these constraints, the use of CNG has often been limited to vehicle
fleets that return to the same location each day. With expanding CNG demand and refueling infrastructure,
this situation is expected to change during the next several years.
The use of CNG as a vehicle fuel usually involves the conversion of a gasoline engine to operate on both
CNG and gasoline (i.e., a bi-fueled engine). The conversion process is relatively simple because no internal
modifications of the engine are required. Conversion equipment generally includes a variable gas-air mixer
as part of the fuel injection system, a series of regulators and valves which deliver the gas from the storage
tanks, and an electronic module to interface with the onboard computer.
Use of LFG to produce CLG (the equivalent of CNG) has gained interest because it provides an alternative
use for LFG projects that cannot utilize all of the CH4 recovered. Using LFG to produce CLG involves
extraction, purification, and compression. In 1994, there were two field demonstration projects in the U.S.
for producing CLG from LFG. The remainder of this section of the report summarizes these projects, as well
as a third project in Tours, France.
11
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2.2.2 Puente Hills Landfill, Los Angeles, California
Background—
The Los Angeles County Sanitation Districts (LACSDs) have demonstrated the technical and economic
feasibility of producing CLG, and its use as a fuel in light-duty gasoline and heavy-duty diesel fueled vehicles
used at the Puente Hills Landfill (Wheless et al., 1996). The CNG demonstration facility has been fully-
operational since October 1993. In 1994, LACSD identified and corrected operational problems and the
facility is now in full service. The facility provides CLG on demand as supplies are depleted at the refueling
station and has a design capacity of 1,000 gallons of gasoline-equivalent (GGE) CLG per day. As of 1996,
the demand has been over 800 GGE per day (Wheless et al., 1996). LACSD is continuing to evaluate the
performance of the CLG processing facility and a wide range of CLG vehicles which routinely operate at the
landfill (e.g., heavy-duty equipment, garbage trucks, and light-duty utility vehicles).
The landfill has a nominal fill rate of 10,000 tons per day (tpd). LACSD installed a gas collection system
which yields about 27,000 standard cubic feet per minute (scfm) of LFG. The LFG (about 22,000 scfm) is
used as a fuel in boilers and turbines to generate 50 MWof power. Another 1,500 scfm is used to generate
power in a 2.8 MW gas turbine. In addition, about 200 scfm is sent to a nearby college for use as boiler fuel.
The motivation for undertaking the demonstration program was that the gas collection system had been
producing excess gas which was not used to generate electricity. This was due to a combination of excess
power generating facilities in the area and the low cost of natural gas which resulted in power rates lower
than the production costs for new power generating facilities. LACSD was interested in finding alternative
uses for the LFG. Use of LFG as a vehicle fuel potentially has both environmental and economic benefits.
The environmental benefit would result from reductions in air emissions if LFG is used as a substitute for
gasoline or diesel fuel rather than being burned in flares for pollution control.
The existing gas collection system is designed to capture the LFG by maintaining a negative pressure within
the landfill and to prevent odors and meet the stringent air emission regulations of the South Coast Air
Quality Management District (SCAQMD). However, this results in air being drawn into the landfill (air
intrusion), and the concentrations of oxygen and nitrogen in the LFG must be reduced to meet the California
Air Resources Board's (CARB's) fuel specifications for CNG (less than 5 percent inert compounds by
volume). Therefore, cryogenic separation would be needed to remove air from the LFG. LACSD
determined that it would be too difficult and expensive to remove the air from the LFG for CLG production.
To get around this problem, wells that extract gas from the deep core of the landfill were identified that had
minimal air intrusion. Then, a new piping system was connected to the wells to draw a richer "core" gas with
less than 1 percent oxygen. An oxygen sensor was installed at the inlet of the processing system to
continuously monitor for air entering the processing system above specified levels. Adjacent wells were
adjusted to insure that proper odor and air emission concentrations were maintained at the surface of the
landfill. This approach limits the quantity of LFG available for vehicle fuel from a selected site. However,
at the Puente Hills Landfill, it requires less than 5 percent of the available gas to meet the needs of the on-
site equipment.
Process Description—
Figure 2-3 shows a diagram of the facility. The facility includes a compression and processing system,
compressed gas storage tanks, and a fuel dispensing station. The equipment is mounted on three separate
skids: the compression skid, the membrane skid, and the gas storage skid. A gas dispensing facility is
located at a convenient place approximately 1,000 ft from the processing and storage skids. The facility is
designed to remove H2O vapor, CO2, H2S, and trace NMOCs which include some hazardous air pollutants.
Table 2-2 shows CARB's specifications for CNG produced from natural gas to ensure consistent emission
test results. The CLG produced from LFG must also meet the specifications. The table also shows the
specifications of the CLG at the inlet and outlet of the processing facility.
12
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TABLE 2-2. Alternative CNG Fuel Specifications Compared to
CLG Produced by the LACSD Project
Constituent
CARBa
LACSD Project
Inlet Gas
Product Gas
CH4
Ethane
HCs (C3 and higher)
HCs (C6 and higher)
Hydrogen
Oxygen
CO
Inert Gas (CO2 and nitrogen)
H20
88% min
6% max
3% max
0.2% max
0.1% max
1 .0% max
0.1% max
1.5-4.5%
0.9 Ib/MMscf
55% min
n/a
n/a
n/a
n/a
0.2%
n/a
0.8%
Saturated
96%
b
n/a
b
n/a
0.2 - 0.3%c
n/a
4%
0.5 Ib/MMscf
a CCR Title 13, Section 2292.5.
b These constituents were analyzed but not detected (detection limits not available).
cWheless, 1997.
A 75 horsepower (hp) rotary vane blower is used to draw 250 scfm of LFG from the dedicated wells into the
processing system. The LFG is saturated with moisture which is removed during the compression and
cooling stages of the process. The condensed Hp is collected in a H2O knockout tank located on the
compressor skid which is emptied into the LFG collection system for on-site treatment. The blower
compresses the gas to 40 pounds per square inch (psi) followed by a series of heat exchangers and
reciprocating compressor stages which compress the gas further to 525 psi, and a maximum temperature
of 115 degrees Fahrenheit (°F). The compressed gas then passes through an activated carbon bed to
remove trace NMOC. Two guard beds are provided in parallel to allow regeneration of the bed media
without disruption in the operation of the system. A silica gel is installed in the top layer of each bed to
remove H2O vapor contained in the gas. If not removed, the H2O vapor would be adsorbed on the activated
carbon thus reducing the efficiency of the beds for adsorbing HCs. The gas then passes through the
activated carbon which selectively adsorbs heavier HCs. The activated carbon used also has a high affinity
for sulfur and halogenated Hcs.
The gas purification membranes (Separex™) consist of a series of spiral wound cellulose acetate membrane
elements fitted into three separate tubular housings. The tubes are connected in series. Since the
membranes used will dissolve in H2O, the gas is heated in a glycol H2O bath to increase the gas temperature
above the dew point before being fed to the membrane purification elements. The temperature is set to
ensure that any moisture present is in the vapor state. The higher temperature also allows for a more
efficient operation of the membrane. The membrane elements are selectively permeable to CO2while
rejecting CH4. The process is enhanced, within operating limits, by a high-temperature and high-pressure
differential across the membrane elements. The permeate, containing about 28 percent CH 4and 72 percent
CO2, is diverted to the energy recovery facility where it is combusted in turbines or boilers. The CH4 content
of the residual product gas is about 96 percent. Of the 250 scfm feed gas, approximately 150 scfm is waste
gas and 100 scfm is product gas.
13
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Dispenser Storage
Control Panel
100 scfm
3,600 psi
-<>-
LFG In
250 scfm
55% CH.
Storage Tanks
rWaste Gas
STAGE 5
COMPRESSION
160 scfm
28% CH,
STAGE 4
COMPRESSION
1560 psi
H2O
Knockout
Tank
Condensate
Recycle
35 scfm 0 psi 80% CH4
STAGE 1
COMPRESSION
' 40 psi
Rotary Vane Heat
Compressor Exchanger
Dispenser
Heater
Carbon
Guard
Beds
STAGE 2
COMPRESSION
96% CH4
3,000 psi
140°F
STAGE 3
COMPRESSION
150 psi
Reciprocating Compressors
525 psi
Figure 2-3. Flow Diagram of the LACSD CLG Production Facility
(adapted from Wheless et al., 1996)
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After passing through the membrane, an odorant is metered into the product gas to provide an early warning
in the event of a leak. The odorant is metered in so as to be detectable at one-fifth of the lower explosive
limit of the product gas. The gas is then compressed in a series of stages to a final pressure of 3,600 psi
and is stored in six 10,000 scf pressure vessels. The entire system conforms to National Fire Protection
Association Code 52 (NFPA 52) which governs CNG vehicular fuel systems. As shown in Table 2-2, the
CLG produced conforms to CARB's fuel specifications for CNG. For this reason, the CLG can be used in
any vehicle designed to operate on CNG with predictable air emissions.
The dual dispenser is similar to a conventional gasoline pump with two fill hoses, a fuel meter, and a card-
operated automatic system to initiate operation and to record billing information. To accommodate the
needs of the CNG fleet, one of the dispensing hoses is dispensing at 3,000 psi and the second hose is
dispensing at 3,600 psi.
To provide a fast-fill operation, storage vessels are emptied sequentially. The six storage tanks are divided
into low, medium, and high pressure banks. CLG is initially dispensed from the low pressure bank and then
switches automatically to the medium and high pressure banks as the gas flow rate to the vehicle falls below
a specified value. The time to transfer the equivalent of 50 gal of diesel is less than 10 minutes (Wheless
etal., 1996).
Evaluation of Alternative Processing Technologies—
LACSD evaluated the Selexol® and pressure swing adsorption technologies, which are the leading
technologies for producing pipeline quality gas (natural gas) from LFG. LACSD decided not to use these
technologies because they are predominantly applied to large gas flow rates [more than 3 million scf per day
(scfd)]; both are usually operated as steady-state, continuous-duty systems with regular operator attention;
and both require some form of license. In addition, the need for the facility to operate intermittently to
replenish the CLG storage tanks was important because fuel usage for the available fleet of CLG vehicles
at the landfill was initially much lower than the facility was designed to produce at full capacity.
Performance—
During initial start-up and operation of the facility, only minor problems were experienced with the processing
system. The problems encountered were associated with properly managing the extraction of the LFG from
the wells and the design of the fuel dispensing facility. Improved instrumentation and training of technicians
was needed to manage the flow of gas from the wells to the system. The instrumentation needed to monitor
and tune the wells had to be more sensitive than what is typically used for LFG recovery projects. Only 1
percent air was allowed in the feed gas; consequently, the oxygen concentration needed to be measured
in the field down to 0.2 percent.
Problems encountered with the facility's design were those that could also occur with normal pipeline gas
CNG fueling stations. The problems encountered were associated with the fuel dispenser and associated
card reader, the odorant addition system, and process instrumentation. The compressors experienced
several failures, but only two of these were attributable to the LFG. There was some H p damage to one
of the first stage compressors, which could be resolved by improving the drain system. Also, the valve
springs in the second stage compressor fractured from corrosion causing damage to the pistons, crosshead
rods, and crosshead bearings. These problems were resolved by using springs of a more suitable steel
alloy.
In 1994, LACSD completed an evaluation of the system and have transferred operation and maintenance
(O&M) of the facility from LACSD R&D engineering staff to technicians responsible for landfill operations.
Vehicles at the landfill are currently consuming about 50 gallons per day (gpd) of diesel equivalent CLG.
LACSD also began trucking CLG to another LFG to energy facility in March 1996 [100,000 cubic feet (ft 5
tube trailer]. With this trailer making one round trip daily, the demand has been increased to over 60 percent
of design capacity (equivalent to about 600 GGE).
15
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The CH4 content of the CLG ranges from 96 to 99 percent and averages 97.5 percent. The oxygen content
ranges from less than 0.3 percent to 0.6 percent. H^S and other sulfur bearing compounds are removed
by the activated carbon beds to more than the 40 parts per billion by volume (ppbv) detection limit.
LACSD plans to review the facility to identify how operation of the facility can be simplified and improved.
Items under investigation include the use of heat from the compressors to replace the gas heater,
elimination or simplification of the carbon guard bed, and restricting the purge gas usage. These
modifications would significantly simplify the process and make the system comparable to standard pipeline
CNG compression stations.
Economics—
LACSD prepared the design specifications for the facility and used a competitive, sealed bid process to
procure turnkey services for construction of the facility. Table 2-3 shows a breakdown of capital costs for
the facility. Costs are presented in 1992 dollars. The total installed capital cost, including design,
construction, and initial start-up was $970,000. The cost of piping for the dedicated wells is not included in
the capital costs. The applicable taxes, LACSD staff costs related to engineering, construction
management, and inspection brings the total cost to approximately $1,100,000.
Operating costs for the facility are presented in Table 2-4 in terms of cents per gallon of gasoline for 25, 50,
and 100 percent utilization. The operating costs include capital recovery costs which were calculated using
a 15-year equipment life and 7 percent interest rate. O&M labor and materials were calculated as 3 percent
of construction costs. Power usage was estimated at 5 cents per kWh. A gallon of gasoline was assumed
to be equivalent to 125 scf of CLG. Because capital recovery represents a majority of the fuel production
costs, fuel usage is key to low cost production of CLG.
CLG project economics will depend on the amount of gas being processed. According to LACSD, the
processing capacity of LACSD's fueling facility represents the minimum economical size. Figure 2-4 shows
the estimated economies of scale for production of CLG using the process developed by LACSD (Wheless
et al., 1996). This figure shows that a facility with a capacity of about 2,000 GGE could be economically
competitive when CNG is sold at $0.70/GGE. The data supporting this figure do not include Internal
Revenue Service Section 29 Tax Credits, the benefits of a NGV fleet, or the costs of a dual LFG collection
system. Further, it is assumed that there is demand for the entire plant capacity.
Many of the capital cost components such as those for the dispenser, storage, and continuous monitors are
independent of processing capacity, while costs related to engineering design, compressors, and the
membrane are expected to increase by only 50 percent if the capacity is doubled. If the fleet of vehicles is
large enough to justify a larger facility, the price per gallon equivalent can be expected to drop to
approximately half the existing cost of diesel or gasoline, and about two-thirds the cost of retail CNG (as
shown in Figure 2-4). If diesel or gasoline prices continue to increase, even smaller facilities may be
attractive.
CNG-powered refuse trucks are more expensive than comparable diesel trucks. Due to economy of scale,
as more trucks are being built, the price per truck is expected to decrease. However, since natural gas is
normally less expensive than diesel fuel, the capital cost of the vehicle will be recovered over time. The
payback time depends on vehicle mileage, fuel economy, and the difference in fuel costs. Based on typical
LACSD annual mileage of 75,000 miles, the estimated $5,000 difference in purchase cost can be paid back
in 2.5 years. This analysis assumes that CLG is available at $0.50 per gallon and diesel at $0.80 per gallon.
(Wheless etal., 1996).
16
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TABLE 2-3. Capital Costs For The CLG Production Facility
Item Cost ($1992)
Compressor Skid 175,000
Membrane Skid 140,000
Dispenser 50,000
Storage 45,000
Instrumentation/Controls 115,000
Electrical 100,000
Miscellaneous 95,000
Engineering, Overhead, & Profit 250,000
TOTAL CONSTRUCTION COST 970,000
TABLE 2-4. Estimate of Fuel Costs for CLG Production
Percent Utilization $/GGE
100 0.48
50 0.74
25 1.26
Basis:
Capital recovery, 15 years @ 7 percent interest.
Power, 50/kWh.
O&M, 3 percent of construction cost.
Gallon of Gasoline = 125 scf of CNG.
17
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$0.90
- Retail CNG
-Total
-O&M
- Capital
•Power
• Membrane/carbon
5,000
10,000
GGE/day
15,000
20,000
Figure 2-4. Estimated Economies of Scale for CLG Production Facilities
Vehicle Demonstration Program—
In late 1991, LACSD initiated a program to evaluate the use of CLG as a clean-burning, alternative fuel for
its vehicles and heavy-duty equipment. LACSD also envisioned that fuel could be made available to users
of the landfill to further reduce air emissions and dependence on petroleum products. According to LACSD,
the program is primarily dependent on the engine manufacturer's ability to produce low-emission, dedicated
CNG engines. Manufacture of low-emission, dedicated CNG engines is an emerging technology with a
limited number of equipment suppliers.
Passenger vehicles—
In mid-1993, a 1988 Ford Taurus V-6 passenger car was converted to run on dual-fuel (CNG and gasoline)
using CARB's approved gaseous fuel injection (GFI) system. The conversion included the addition of two
5.5 GGE CNG cylinders in the trunk with a manual switch to select the fuel desired. In the dual-fuel
applications, the GFI system is designed to automatically return the engine to gasoline operation when the
gas fuel storage pressure drops below a preset minimum.
The use of this vehicle was discontinued in October 1996 due to the age of the vehicle. The cooling system
in the vehicle needed overhaul and it would have cost more than the vehicle was worth. The operation of
the CNG system was considered successful and the driver was pleased with the performance.
Since the conversion, the vehicle has traveled predominantly on CLG for over 22,000 miles. The car has
averaged 20 miles per GGE when using CLG for both city and highway driving, which is comparable to
operating on gasoline. The performance of the vehicle was excellent according to LACSD. A temporary
18
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problem was encountered with the GFI system which caused the car to stall and surge; however, this
problem was fixed.
Light-duty trucks—
Since mid-1992, LACSD have been operating a CMC 3/4-ton Sierra pick-up truck that uses only CLG. The
vehicle is one of 1,000 light-duty vehicles produced by the CMC Truck Division with assistance from the
Southern California Gas Company. The initial operating experience was poor with problems including
engine stalling and surging, limited mileage per GGE, and lack of experience of the dealer service
personnel. After replacing fuel injectors several times, repairing the throttle body meter, cleaning the fuel
tank solenoid, replacing the fuel pressure regulator, and adjusting the timing, the performance improved,
and the vehicle was operating like a conventional gasoline engine model. An additional ten GGE CNG
cylinder was also installed to increase the driving range of the vehicle.
LACSD's first pick-up truck was eventually recalled due to CNG cylinder safety concerns. LACSD
subsequently acquired a replacement 1994 CMC Sierra 2500 gasoline-fueled truck. This vehicle was
converted by NGV Ecotrans to bi-fuel (use either gasoline or CLG) with the GFI system. The vehicle is used
off-road at the landfill during the day, and is driven to and from the site at other times. Since August of 1994,
the truck has accumulated over 16,000 miles fueled predominantly on CLG. The truck has achieved an
average fuel economy of over 13 miles per GGE. Drivers report little to no noticeable power loss between
the two fuels for this vehicle.
Medium-duty vehicles—
In 1995, LACSD purchased six Chrysler dedicated CNG minivans for the rideshare program. The vans are
fueled with CLG. The vans are partially funded by the California Assembly Bill 2766 Discretionary Fund
Program administered by the Mobile Source Air Pollution Reduction Committee, and the California
Department of Transportation. Assembly Bill 2766 authorized an additional $4 fee per vehicle registration
which is collected by the California Department of Motor Vehicles. The fee is provided to the SCAQMD
annually to fund various research projects for reducing air emissions from motor vehicles.
The dedicated Chrysler CNG minivans are certified by GARB as ultra-low-emission vehicles (ULEVs). The
vans are fitted with sequential multi-point fuel injection, heated oxygen sensors, exhaust gas recirculation,
and a three-way oxidation catalytic converter.
The vans are originally equipped with three CNG cylinders mounted under the body chassis, each carrying
eight GGE. To increase the driving range of the vehicles, each van was installed with an additional six GGE.
The driving range (175 to 200 miles) of the vehicles is still limited, which causes a lot of complaints from the
vanpool. No significant problems associated with the use of CLG has occurred. The average fuel economy
of the vans is 20 miles per gallon equivalent.
Heavy-duty vehicles—
LACSD has been operating a new water truck on CLG for dust control at the landfill since October 1993.
The truck is a CMC conventional cab-chassis with a Hercules 5.6 liter (L), 6-cylinder, dedicated natural gas
engine. This medium-duty engine is being used in trucks and buses rated between 15,000 and 30,000 Ib
gross vehicle weight and is the first CARB-certified engine that meets emission standards without exhaust
after-treatment. The engine is a lean-burn combustion system equipped with a turbo-charger and after-
cooler which provides a maximum output of 190 hp. When operating properly, the vehicle provides
adequate power on inclining grades.
Since 1993, the water truck has only been driven approximately 13,000 miles at the landfill using strictly
CLG. This truck has had its share of problems, mostly related to the fuel (GFI) and electrical systems. In
three years of its operation, six compuvalves were replaced. Most of the problems were related to the
compuvalve draining of the battery, and when the battery voltage is below nine volts, it causes the GFI to
fail and damages the low flow injectors (o-ring in the injectors gets hot and causes fuel leakage). When the
vehicle is jump started, the voltage is too high and it fries the microcompressor. GFI improved the
19
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compuvalves with Generation II by having the low- and high- voltage protection. The compuvalve II was
installed, and still had the same problem. Hercules and GFI have no clues to what is causing the problem.
Due to continual problems and complaints from operators, this truck was re-powered with a CAT3126 dual-
fuel engine in February 1997. Since then, the truck has only accumulated 1,500 miles. The truck has not
been used very much because of non-engine related problems, such as transmission and hydraulic pump
systems. On the dynamometer, power output is identical between diesel and dual-fuel firing (Wheless and
Wong, 1996).
A 1986 Volvo White refuse packer truck was re-powered from a diesel engine to a Detroit Diesel Series 50
dedicated CNG spark-ignited engine. The truck was provided by Athens Disposal for the demonstration
program with funding provided by the Assembly Bill 2766 Discretionary Funding Program. As of
October 1994, the Athens Disposal vehicle had accumulated well over 10,000 miles running solely on CLG.
The vehicle achieved approximately 2.3 miles per gallon of diesel equivalent, which is comparable to the
fuel economy of the diesel engine priorto conversion.
Potential heavy-duty vehicles—
In 1994, LACSD received funding through the Assembly Bill 2766 Discretionary Funding Program to convert
two water trucks and two refuse transfer tractors from diesel to CLG. The water trucks and one refuse
transfer tractor will be using the low-emission technology identified by MARK I and MARK II systems
developed by Clean Air Partners, Inc. The MARK II system uses pilot ignition which allows leaner gas/air
fuel ratios with a minimum plasma ignition of 1 percent diesel and a very lean mixture of CNG, which is
expected to result in very low emissions.
LACSD re-powered an existing class eight tractor with a rebuilt Cummins N14 dedicated CNG engine. The
tractor is used to haul sludge and travels about 200 miles per day. A new class eight refuse transfer tractor
was purchased with a dedicated CNG Detroit Diesel Series 60 engine. The tractor will be used to haul
refuse from a transfer station to the landfill. The CNG Detroit Diesel Series 60 engine is a 6-cylinder version
of the 4-cylinder Series 50 used in the Athens' refuse truck. The engine is capable of providing from 350
to 450 hp with a minimum of 1,200 foot-pounds of torque. The engine is expected to produce significantly
lower emissions than a typical diesel engine used to haul refuse throughout its entire operating range.
Emissions—
Emission reduction benefits resulting from the production and use of CLG are primarily associated with the
reduction in vehicle emissions. There are, however, some emission reductions associated with recovering
the CH4 from the LFGto produce CLG rather than burning the CH4 in flares. In addition, there are emissions
associated with the disposal of waste gas generated during the purification process. In the LACSD system,
the waste gas is combusted in an on-site energy recovery facility. Emissions of CO, volatile organic
compound (VOC), and PM from combustion of the waste gas are expected to be small. Emissions of NOX
from combustion of LFG in flares or turbines is on the order of 0.09 Ib/MMBtu (Roe et al., 1995).
Table 2-5 shows GARB standards for existing and low-emission vehicles (LEVs), and CARB's certified
emission standards for the 1992 CMC 3/4 ton Sierra pick-up truck, 1994 Chrysler minivan, and 1993 Ram
Van models. For the Sierra pick-up truck operated on CNG, CARB's certified non-methane hydrocarbon
(NMHC) emissions are between the GARB standards for transitional low-emission vehicles (TLEVs) and
LEVs. The pick-up truck's CO emissions are between CARB's standards for LEVs and ULEVs, and its NOX
emissions are significantly less than CARB's standards for ULEVs. The pick-up truck's certified NMHC and
NOX emissions for CNG are 50 percent less than the certified emissions for gasoline fuel; however, CO
emissions are higher than for gasoline.
20
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TABLE 2-5. Comparison of Emissions For Light-Duty Trucks
and Medium-Duty Vehicles
Emissions (gram/mile)
Vehicle Type
Liqht-Dutv Trucks
GARB Standards
Existing
TLEV
LEV
ULEV
GARB Certified Emissions
1992 CMC 3/4 ton Sierra, Gasoline
1992 CMC 3/4 ton Sierra, CNG
1994 Chrysler Minivan, CNG
Medium-Duty Vehicles
GARB Standards
Existing
LEV
ULEV
GARB Certified Emissions
1993 Ram Van, Gasoline
1993 Ram Van, Dedicated CNG
NMHC
0.50
0.16
0.10
0.05
0.29
0.14
0.021
0.60
0.20
0.12
0.19
0.03
CO
9.0
4.4
4.4
2.2
2.2
3.8
0.35
9.0
5.0
2.5
3.4
2.3
NOX
1.0
0.7
0.4
0.4
0.4
0.2
0.04
1.5
1.1
0.6
0.5
0.05
The dedicated CNG Chrysler Minivans and Ram Vans are certified by GARB as ULEVs and LEVs,
respectively. CARB's certified NMHC, CO, and NOX emissions for both vehicle models are significantly less
than CARB's standards for ULEVs. Certified NMHC, CO, and NOX emissions for the 1993 Ram Van
dedicated to CNG are significantly less than CARB's certified emission standards for gasoline.
Emission tests were performed on the Hercules 5.6 L diesel engine used to operate the water truck. Table
2-6 shows the emission test results for the medium-heavy-duty water truck operated on CNG relative to
emissions for a typical diesel equivalent and CARB's standards for heavy-duty vehicles. Emissions of
NMHC, CO, NOX, and PM for the Hercules engine are significantly lower than CARB's emission standards.
Emissions of NOX and PM are lower than emissions for a typical diesel equivalent, but NMHC and CO
emissions are higher than for a typical diesel equivalent engine.
21
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TABLE 2-6. Comparison of Emissions for Medium-Heavy-Duty Trucks
and Heavy-Duty Trucks
Emissions (gram/brake hp-hr)
Vehicle Type
NMHC
CO
NOV
PM
Medium-Heavy Duty Trucks
CARB's Existing Standard
Typical Diesel Equivalent
Hercules 5.6 L, CNG engine
Heavy Duty Trucks
CARB's Existing Standard
Typical Diesel Equivalent
Detroit Series 50, CNG engine
1.3
0.5
0.9
1.3
0.5
<0.5
15.5
1.6
2.8
15.5
2.0
<2.0
5.0
4.7
2.0
5.0
4.6
<2.0
0.10
0.24
0.10
0.10
0.23
<0.05
Baseline emission testing on the refuse packer truck was conducted to determine the net air emission
reductions for converting the refuse packer truck from diesel to CNG fuel. The Detroit Diesel Series 50 CNG
engine was certified by GARB in mid-1994. Table 2-6 shows the expected emission values for the CNG
engine relative to a typical diesel equivalent engine and CARB's standard. Emissions of NMHC, CO, NOX,
and PM for the CNG engine are significantly lower than CARB's existing standards, and slightly lower than
emissions for the diesel equivalent engine.
Secondary Environmental Impacts—
The facility is designed to remove Hp vapor, CO2, H2S, and trace NMOC which include some hazardous
air pollutants from the LFG. The LFG is saturated with moisture which is removed during the compression
and cooling stages of the process. The condensed H2O is collected in a H2O knockout tank located on the
compressor skid which is emptied into the LFG collection system for on-site treatment. Information on the
type and amount of pollutants collected in the H2O knockout tank was not available. However, because the
condensate is treated in the existing leachate treatment system, the incremental costs for treatment are
negligible.
Baseline emission testing on the refuse packer truck was conducted to determine the net air emission
reductions for converting the refuse packer truck from diesel to CNG fuel. The Detroit Diesel Series 50 CNG
engine was certified by GARB in mid-1994. Table 2-6 shows the expected emission values for the CNG
engine relative to a typical diesel equivalent engine and CARB's standard. Emissions of NMHC, CO, NOX,
and PM for the CNG engine are significantly lower than CARB's existing standards, and slightly lower than
emissions for the diesel equivalent engine.
2.2.3
Tork Landfill, Wisconsin Rapids, Wl
Gas Resources Corporation (GRC) of Colorado installed a CLG conversion process in 1994 at a LFG
utilization facility in Wisconsin Rapids, Wl. The LFG utilization facility was designed to produce LFG product
gas equivalent to pipeline-quality natural gas. The product gas was used to heat three buildings and to fuel
two RIC engines to produce electrical power for the site. Additional LFG product gas was sold to a nearby
asphalt plant for use as process fuel. GRC designed and installed a small demonstration facility to produce
CLG from excess LFG product gas. The system was successfully brought on-line with no major technical
22
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problems. However, because only two CNG-powered vehicles were available for consumption of the CLG
produced, the facility was not economically viable (initial plans had called for additional use of CLG in
garbage trucks). In 1995, the facility was shut down, and the equipment was sold to Westchester County,
New York for use at the Croton landfill in New York metropolitan area (Bahl, 1997). A brief description of
the projects at both the Tork and Croton Landfills follows.
At the Tork Landfill, the gas processing facility was a skid-mounted prototype that was operated 24 hrs per
day and produced gas with as high as 96 percent CH 4 The facility was equipped to convert CH4to CLG
which was used as fuel for two pickup trucks. The gas processing facility included two separate steps. The
first step was the cleaning of the gas to remove moisture and NMOC. This gas cleaning step is a patented
process where moisture and NMOC are condensed out of the gas using elevated pressures (200 psi) and
reduced temperatures.
The second step involved separating CO2from the CH4. This was done by mixing the gas with a liquid
solvent called Selexol®, which is a poly-glycol compound sold by Union Carbide. The SelexoP solvent has
long been used by gas processors and refiners; however, it has only been made available to the general
public for the last few years. When the Selexol®solvent is mixed with the gas under high pressure, CO 2
goes into solution. The Selexol® is then depressurized, allowing the CO2to come out of solution where it
is discharged to the ambient air. The Selexol® is then recirculated through the system for reuse.
During start-up at the Tork Landfill, some problems were encountered. For example, the Selexol ®
compound dissolved rubber seals in valves and pumps which required replacement with seals that would
not be dissolved by the Selexol® compound. After shake-down of the system was completed, the process
was operated for six months without interruption. The major operational problem noted was an undersized
fuel delivery system (e.g., storage tank, compressor) which required extensive periods of time for refueling
(Bahl, 1997).
The capital cost of the facility used at the Tork Landfill was $400,000 in 1992. GRC received a $75,000
grant from the State of Wisconsin to fund construction of the facility. The cost of converting each of the two
pick-up trucks to operate on CNG was about $2,600 in 1992. The Wisconsin Rapids area is too small in
population to qualify for the tax breaks under The Energy Policy Act of 1992, which includes provisions for
vehicle fleets to deduct a significant potion of the cost of buying and outfitting a truck to burn alternative
fuels.
At the Croton Landfill, the system has been running with no significant problems for about 15 months (Gavin,
1997). Savin Engineers (contractor to Westchester County) upgraded the fuel storage and compression
equipment prior to start-up. Problems encountered have been related to typical O&M issues (e.g.,
replacement of seals on the Selexol® pump). The system produced CLG with 85 to 95 percent CH 4for use
in several county vehicles. Plans are to also use the fuel in two county tractor trailers that are being
converted to use CNG. The CLG produced has met specifications set by GARB (see Table 2-2). The
equipment is currently processing 20,000 scfd of raw LFG containing over 50 percent CH 4 The Croton
Landfill is a 113 acre site currently producing a million scfd. Economic analyses will soon be performed to
determine the economic viability of a commercially sized system. The biggest preliminary concern is the
availability of a large enough customer base for the CLG produced, especially since there is already a local
CNG supplier (Gavin, 1997).
2.2.4 Sonzay Landfill, Tours, France
Background—
The SITA Group (Paris, France) successfully demonstrated another CLG project at the Sonzay Landfill near
Tours, France (about 135 miles southwest of Paris). This landfill supports a population of about 125,000,
opened in 1985, and accepts approximately 100,000 tpd of municipal (80 percent) and non-hazardous
industrial (20 percent) waste (Balbo, 1997). The landfill site covers 222 acres with 150 acres allocated to
23
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landfill operations. Planning for the CLG facility began in 1993, and the facility has been fully functional
since 1994.
Process Description—
The LFG undergoes primary compression to approximately 200 psi via two stage compression. After both
low-end and high-end primary compression, the LFG is cooled with a heat exchanger. In the second step,
the crude CLG is scrubbed with H2O in a packed counter-current wet scrubber. The H>O absorbs most of
the CO2 and H2S out of the crude CLG. The H2O containing the CO2 and H2S is then regenerated by
introducing it back into the top of the column and stripping these compounds out using ambient air. The air
exhaust stream from the scrubber is then cleaned in a biofilter. It is important to note here that this
demonstration project has shown the technical feasibility of using a physical absorption system using H2O
instead of a chemical absorption system which may have associated secondary environmental impacts and
costs.
The third step in the process is drying. The scrubbed CLG is passed through an adsorption column using
an undisclosed adsorbent. The system uses dual columns, so that one column can be regenerated while
the other is operating. The final step is secondary compression via another two-stage compressor.
Following both the low pressure and high pressure compression stages the CLG is cooled by heat exchange
with circulating H2O.
Following secondary compression, the gas is analyzed for CH4 content. The CLG is then either stored on-
site or in a city of Tours mobile storage unit (about a 950 gal capacity). The on-site storage consists of 120-
50 L bottles (approximately a total capacity of 1,600 gal of CLG or 400 gal of diesel fuel). Excess or poor
quality CLG is flared.
Performance—
As mentioned above , the facility has been fully functional since 1994. The facility has produced both a high
Btu CLG (86 to 95 percent CH4) and a high Btu CLG (about 97 percent CH4). Oxygen in the final products
is less than 0.5 percent and H2S is less than 5 ppmv. SITA estimates that for each ton of waste landfilled,
they can produce just over a half gallon of CLG for up to 15 years (Balbo, 1997). No additional information
was available as to system downtime, malfunctions, or other performance issues.
The city of Tours converted 30 small cars to run on either CLG or diesel fuel. SITA reports that it takes an
average of 5 minutes for a typical filling operation. Each car has a CLG capacity of about 21 gal, yielding
a 130 mile range. Combined with the existing diesel fuel tank, the cars have a total range of about 450
miles.
Genet (the subsidiary of SITA, which runs the landfill) also retrofitted mini-vans and a waste-haul truck to
run on CLG. The 40-ton waste-haul truck transports compacted waste from a local transfer station four
times daily and covers a total daily distance of 130 miles. The truck has an effective range of 98 miles and
therefore must refuel twice daily (filling time is approximately 15 minutes). No additional information was
available as to vehicle malfunctions or performance.
Economics—
Capital costs for the CLG plant are estimated at about $900,000 [1994 dollars (DuPuis, 1996)]. No
information was available on operating costs. It should be noted that fuel costs are much higher in Europe
than the U.S. Hence, a process such as the one described above may be economically feasible in Europe,
but not in the U.S. or other parts of the world.
24
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2.3 Leachate Evaporation
2.3.1 Introduction and General Overview
Leachate collection and treatment is one of a number of environmental concerns of MSW landfill operators.
Landfill design, construction, and operating costs can be heavily influenced by needs for leachate collection,
conveyance, storage, treatment, and disposal.
In some landfills in arid or semi-arid climates, precipitation, humidity, and soil conditions are such that little
or no leachate is generated. Therefore, in these instances, no leachate collection is needed. In some
areas, local jurisdictions allow leachate to be collected and recirculated (i.e., returned to the landfill using
an appropriate delivery method). This is usually the most economical alternative when leachate is present.
Leachate also may be accepted at a municipal waste water treatment plant directly through a sanitary sewer
line. As leachate is a very high strength waste, compared to industrial waste waters, an additional fee may
be required. In cases where a sewer line is not available, it may be necessary to truck the leachate to a
treatment plant. This may or may not be a permanent solution, as future acceptance of leachate is at the
treatment plant's discretion.
If recirculation or off-site disposal are not options, on-site treatment is usually the next option. On-site
treatment includes evaporation ponds, aerated stabilization basins, filtering systems, and biological and
chemical treatment facilities. Treatment plants generally must include chemical processes to remove metals
through pH adjustment, followed by biological treatment. Biological treatment may be combined with
powdered activated carbon treatment to remove organic compounds and often includes anaerobic and
aerobic treatment with or without nitrification.
The principle of leachate evaporation systems (LESs) is simple and direct: use LFG collected at the site as
an energy source to evaporate H2O and combust the organic compounds in the leachate. Depending on
local requirements, the highly concentrated (hence very low volume) effluent is returned to the landfill or
shipped off-site for disposal. LESs concentrate and precipitate metals, primarily as salts, while stripping
organics to a thermal oxidizer (e.g., flare) or RIC engine for destruction.
There are several variations of leachate evaporator systems. They differ only in the methods used to
transfer heat to leachate and how the exhaust vapor is treated. One commercial design theme simply
destroys the leachate vapors and LFG not consumed in the evaporation process in a slightly modified
enclosed flare [Organic Waste Technologies, Inc. (OWT)]. Another variation combusts the evaporated
vapors and LFG in an RIC engine to produce electricity; the waste heat from the engines is used to aid in
evaporating the leachate (Power Strategies L.L.C.).
2.3.2 LES and Technair System
Process Description—
OWT offers two LESs. The LES is marketed through its Omni-Gen Technologies, Inc. subsidiary. OWT is
also a licensee of the Technair system (Italy). A schematic of the LES is presented in Figure 2-5. A process
flow diagram for a 10,000 gpd LES with typical flow quantities is presented in Figure 2-6. Leachate is
continuously fed to the evaporator vessel. A LFG-fired burner introduces hot gas into the leachate as fine
bubbles below the surface (gas sparging) and direct heat transfer occurs between the liquid and hot gas.
The leachate is maintained at 180 to 190 °F. Direct contact of hot gases with leachate acts to strip most of
the organic compounds within the leachate to the vapor phase. Organics are transferred from the liquid
leachate phase to the exhaust vapor phase by a process analogous to air stripping (i.e., contaminants
partition between the vapor and liquid phases according to their respective vapor pressures and
concentrations within the liquid). As the process occurs at elevated temperatures, the stripping action is
25
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EXHAUST
GAS BURNER --,
LEACHATE IN •-
*•
EVAPORATOR
VESSEL
RESIDUAL — i
RESIDUAL OUT
(TYPICALLY ~~
30% SOLIDS)
\
C
^
u.
1
1
-.
f
^=- LFG IN
f>
^^,^ DOWNCOMER
c
w
. to
MIST ELIMINATOR
SECTION
P^~~
_1
^J^r^
- PUMP
1400" -1600° F
ENCLOSED
FLARE
(OXIDIZER)
•iifc. HO:''
- LFG IN
. COMBUSTION
SUPPORT PAD
HOT TO SCALE
Figure 2-5. Schematic of OWT LES
162 scfm @ 50% CHX
FROM (\ ^j
MAIN LFG <^
BLOWER LFG BOOSTER BLOWER
1 ,250 scfm
^
AIR BLOWER
\ 6.9 gpm
LEACHATE
INLET
EVAPORATOR
BURNER
V V
EVAPORATOR
TYPICAL FLOW RATES
10,000 gpd SYSTEM
A
7,750 scfm
COMBUSTION
GAS 2,500 scfm
AIR, VOC'S
H2O VAPOR &
STRIPPED
FLARE
0.2 gpm
CONCENTRATED
LEACHATE
350 scfm
@50% CH
MAIN LFG
BLOWER
4,900 scfm
AIR
Figure 2-6. OWT/LES Sample Process Flow Diagram
26
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generally more efficient than that obtained with most conventional air strippers operating at ambient
temperatures.
The high vapor pressure and high concentration in the liquid phase promote efficient mass transfer to the
gas phase in vapor stripping. Mass transfer of low vapor pressure organics at low concentrations is
enhanced by the fact that the average residence time of liquid in the evaporation zone is long, typically
measured in minutes or hours, and the total volume of vapor in contact with liquid is relatively large. The
VOC-laden, saturated air is fed to the flare, where it is thermally oxidized.
A process flow diagram of the Technair system is presented in Figure 2-7. The Technair system uses
indirect heat transfer from hot air that has been heated by a LFG burner. Leachate is circulated and
concentrated in two tanks in series. Evaporation/stripping occurs in the densifier. VOC-laden air from the
densifier is preheated and is introduced to the combustor, along with LFG. Thus, the burner provides
thermal energy for both evaporation and thermal treatment of exhaust gases.
fl Air Inlet
/ Leachate
/ Concentrate
Tank
Gas Inlet
Leachate
Tank
yLeachate y
C9ncentrate
Disposal
Exhaust
Figure 2-7. OWT/Technair LES
Performance—
Adequate energy from LFG must be available to treat the quantity of leachate generated. The amount of
energy required to evaporate one pound of Hp from leachate is approximately 1,150 Btu, based on the
sensible heat (one Btu/lb-°F) and latent heat of vaporization of H2O (approximately 1,000 Btu/lb; as the total
concentration of organic compounds is relatively small, the energy requirement to heat and vaporize these
contaminants may be neglected). Assuming heat losses within the evaporator are 15 percent, and that an
additional amount of heat is necessary to evaporate the amount of leachate that is raised to the operating
temperature of 180 °F, but is not evaporated (about 3 percent), the total heat required is about 1,350 Btu/lb
leachate. Assuming LFG containing 500 Btu/scf, the required gas flow to treat one pound of leachate feed
is approximately 2.7 scf/lb, or 22.5 scf/gal.
27
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Fuel requirements for the thermal oxidation portion of the process varies according to the quality and
quantity of vapor generated in the evaporation process. Based on OWT's operating experience the LES
requires approximately 50 scf of LFG in the thermal oxidation section for each gallon of leachate feed
treated. Therefore, it is estimated that the amount of LFG required to evaporate one gallon of leachate and
treat the resultant exhaust vapor in the LES process is 22.5 + 50 = 73 scf/gal.
Less energy may be required for thermal oxidation if waste heat is recovered. The Technair system can be
configured to include waste heat recovery. According to OWT, experience with this system in Italy using
heat recovery has shown that overall LFG use can be reduced to 45 scf/gal at 50 percent CH 4in the LFG
feed.
OWT claims experience showing that 25 to 35 percent total solids in leachate effluent can be achieved by
the LES and Technair evaporators, resulting in a significant volume reduction. Thus, for a hypothetical
example of leachate feed concentration at 5,000 parts per million (ppm) solids and 25 percent total solids
in effluent, the cycles of concentration (C) is:
Cc =
substituting,
Cc = (25/1 00)7(5,000/1 0s) = 50
Assuming leachate feed specific gravity (sg.) is equal to H2O: 1.0, and effluent specific gravity (sgj) is 1.2
(representative of 25 percent aqueous salt solution), the percent volume reduction can be calculated by:
100 - [(1/C^ x(sg1/sg2) x (100)] = % volume reduction
substituting,
100 - [1/50 x (1 .0/1 .2) x 100] = 98.3% volume reduction
Emissions —
No emissions test data are available for LESs using an enclosed flare to destroy LFG and organic vapors
from leachate evaporation. Enclosed flares are considered to be best available control technology for LFG
control. The amount of organic loading from evaporation is small; for example, adding only approximately
10 Ib/day for a 10,000 gpd unit handling leachate at 100 ppm or less of organic compounds (typical).
Emissions should be comparable to a well-designed enclosed flare operating on LFG.
Secondary Environmental Impacts —
As metals will remain in the concentrated leachate residue, testing was performed to confirm that no
secondary problems exist. To date, all leachate processed in commercial and pilot scale LES and Technair
evaporators has produced effluent that passes EPA's Toxicity Characteristic Leaching Procedure (TCLP)
test as non-hazardous. In most cases, the concentration of all metals have been undetectable; the highest
observed concentrations have been approximately 20% of the allowable level of any hazardous constituent.
Thus, the effluent may be returned to the landfill.
Economics —
See costs reported for Orchard Hill Landfill and Sogliano al Rubicone Landfill below.
Demonstration Projects —
A 1 ,000 gpd LES is in demonstration service at the Brookhaven Municipal Landfill on Long Island, New York.
This pilot scale evaporator was built through a partnership comprised of the New York State Energy
Research and Development Authority, the Town of Brookhaven, EMCON, and Wehran Energy Corporation.
The evaporator system is available for treatability tests on leachate and other dilute aqueous waste streams.
The Brookhaven LES is sized to run one tankwagon (6,000 gal) of typical leachate for each pilot test.
The first full-scale LES was built and demonstrated at the Orchard Hill Landfill in Watervliet, Michigan in
September of 1992. EMCON and Balkema Brothers, Inc. were partners in this venture. Prior to installation
28
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of the LES, leachate from the Orchard Hill Landfill was pre-treated and hauled approximately 40 miles to
the Kalamazoo, Michigan wastewater treatment plant at a cost in excess of $0.11 per gallon. LFG was
treated within an enclosed flare. Pretreatment consisted of pH adjustment and precipitation of heavy metals.
Currently, Orchard Hill Landfill evaporates an average of more than 6,000 gpd of untreated leachate feed.
Effluent at up to 30 percent total solids is returned to the landfill. Approximately one hour of labor per day
is required to operate the evaporator. Annual maintenance costs are reported by the operator to be less
than $25,000 per year. The estimated capital cost for this LES is $550,000 (1996 dollars).
The only problem encountered with the Orchard Hill LES related to the design of the gas sparging system.
As a first full-scale demonstration project, the gas sparging system was originally constructed of carbon
steel. Due to corrosion, the carbon steel parts were replaced in-kind with stainless steel after approximately
3 years of operation. As a result of this experience, LES evaporators are now built with higher alloy
components.
The Orchard Hill LES is designed to fire approximately 125 scfm of LFG in the evaporator burner, and
approximately 280 additional scfm within an attached enclosed flare. As with all LES units, the gas volume
required in the flare section is a minimum value. Additional quantities up to the full capacity of the flare may
be burned without affecting performance of the evaporator.
Technair (Concordia, Italy) constructed and placed their first commercial-scale unit into operation at the
Sogliano al Rubicone Landfill near Bologna during 1992. The University of Modena provided technical
support to Technair during the start-up phase of the project. Heat exchange devices were added to the
design because the available volume of LFG at the site could not support a system without the assistance
of waste-heat recovery. As a result of the addition of heat exchangers, only approximately 45 scf of LFG
is required per gallon of leachate treated. The design rate for leachate evaporation for this Technair system
is approximately 6,500 gpd.
The only operational problems with the Sogliano al Rubicone evaporator were with the quality of LFG and
inconsistency in the electrical power supply. While the system did function with LFG at only 30 percent CH4
during the start-up phase of the gas collection system, the maximum evaporation rate was reduced.
Improvements in the gas collection system subsequently raised CH4levels to 40 percent and solved this
problem.
An automated re-start system was added to accommodate frequent power outages. An on-site electrical
plant fueled by LFG was added. Reported on-line time for the Technair unit is 95 percent of available hours.
The plant has logged more than 25,000 operating hours without equipment failure. Reported installed cost
is $750,000. Annual operating and maintenance costs are running at $5,000. Although the labor history
for this system is not available, like the LES, the Technair system is designed to run unattended for periods
of days.
Discussion—
As of late 1997, there were three commercial operating LES units in the US, plus the demonstration project
in Brookhaven. An additional five units are scheduled to come on line in the spring of 1998.
Future projects planned for LESs include: developing evaporation systems that run on waste heat from LFG
engines; integrating control of NOxand SOX emissions from LFG flares and LFG driven engines with
leachate evaporation; and controlling H^S emissions from landfills within the evaporators. Benefits that can
be realized by success in these areas include: broadening the applicability of leachate evaporation to sites
where significant LFG is committed to power generation; providing an additional revenue stream for LFG
to energy plants; and reducing the potential for sites to exceed "major source" trigger levels under the Clean
Air Act. If LFG combustion has occurred historically at the site, potential reductions in NOX and SOX might
be marketable as emission credits in certain non-attainment areas.
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2.3.3
Vaporator System
Process Description—
Power Strategies L.L.C. markets a leachate destruction system, named the Vaporator™ (patent pending).
The Vaporator also uses energy from LFG to evaporate leachate to a solid substance which can be returned
to the landfill, and generates electricity to run all the electrical needs of the system. Additional electricity may
be sold to a utility.
The primary equipment components include a fuel/compression/process skid, Vaporator, Engine Generator
System, and a proprietary enclosed flare system. Fuel supply for the gas compression/processing skid is
taken from the main LFG blower (compressor) discharge prior to delivery to the flare for incineration. Fuel
gas is supplied to the internal combustion engine, which drives the Power Strategies P2™ tuned-reflux
generator.
A process flow diagram for a typical system capable of destroying 5 gpm of leachate and generating 95 kW
of electrical power is presented in Figure 2-8. The Vaporator requires 5 MMBtu/hr of energy from LFG to
vaporize and destroy up to 5 gpm of leachate. The vapor or steam is controlled by a pressure-regulated
valve and is released to the flare through an insulated flow line. The proprietary LFG flare provides for final
destruction of the leachate steam. The vaporization process is a closed loop system, which the
manufacturer claims provides for no odor or spillage.
Combustion
Exhaust
Leachate Inlet
@ 5 gpm
— >
— ^
1
Vaporized Leachate
138 scfm LFG ^
Enclosed
Flare
183scfm Inlet LFG
1,000 scfm LFG
Main LFG
Blower
Electric Power to Grid
T
Note: Vaporator requires quarterly or
semi-annual cleanout for dry solids removal.
LFG in from Wellfield
(450 Btu/scf Assumed)
Figure 2-8. Power Strategies™ Leachate Destruction System
Enclosed LFG flare capacities vary from 1,000 to 5,000 scfm of LFG. Generator systems are available
from 95 to 1,000 kW self-contained units, which can be configured in parallel, depending on specific
needs.
Performance—
As of mid-1997, Power Strategies L.L.C. has four Vaporator units installed and operating, with four more
projects in the design, engineering, and permitting stages, all in the U.S. The first prototype was designed
to handle up to 5 gpm of leachate. It was installed in Quail Hollow, TN in mid-1995 and is still in commercial
30
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operation. It is presently processing 3 gpm of leachate, as that is all that is generated at the site. All
subsequent Vaporators are also 5-gpm modules. The second and third installations were in early 1997
(Virginia) and mid 1997 (Oregon). The fourth installation (also located in Virginia) is in startup mode as of
September, 1997.
According to the manufacturer, the systems have been operating as expected, with only minor problems,
such as supply pump leakage requiring a change in pump seals, and several leaky valves requiring
repacking. The overall percentage of time the Vaporator systems have been online, or available for use
while waiting for other systems to come back online, is in excess of 90% (Echols, 1997).
Emissions—
Emissions from the Vaporator system are generated from the following:
• Vaporator burner;
• RIC engine driving the generator; and
• flare used to destroy the LFG and leachate steam
Emission tests were conducted by Power Strategies to compare emission rates for flare-only operation and
full system operation (i.e., Vaporator, engine and flare). LFG flow was approximately 1,100 scfm during the
tests, leachate flow was 5 gpm, and electricity generation was 95 kW. The manufacturer reports that for
flare-only operation, emission rates of NOX and CO were 2.84 and 4.32 Ib/hr, respectively. With full system
operation, emission rates of NOX and CO were 3.49 and 0.58 Ib/hr, respectively. Thus, with full system
operation, NOX emissions increased by 23 percent and CO emissions decreased by 87 percent compared
to flare-only operation.
Secondary Environmental Impacts—
No secondary environmental impacts are known. The Vaporator requires periodic cleaning (once every 3
to 6 months) to remove dry leachate solids, which resemble beach sand. The manufacturer claims that
leachate solids have passed comprehensive TCLP testing with "non-detect" results on all tests to date. The
dry solids are returned directly to the landfill.
Economics —
The installed cost of a Vaporator system capable of destroying 5 gpm of leachate and generating 95 kWis
estimated to be about $750,000. At least one 95 kW generator system is recommended by the
manufacturer to offset project electrical costs for operating LFG blowers and other electrical equipment. The
landfill operator must determine whether it is advantageous to purchase more generating capacity by
analyzing the local market and considering the cost of electricity, the wholesale price of electricity, the
impacts of deregulation, etc. No data were available on operating and maintenance costs.
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3.0 TECHNOLOGIES UNDER R&D (TIER 2)
Tier 2 technologies are those that are currently undergoing additional R&D, have been tested at the bench-
or field-scale, and may be ready for commercial application. These technologies include both methods
where the CH4 in LFG is used as an energy source as a method for managing landfills to prevent or
minimize the formation and release of CH4and other organic compounds (aerobic bioreactors).
The first two technologies, operating landfills as either anaerobic or aerobic bioreactors, are common in that
the objectives are to increase the rate of waste biodegradation by enhancing the environmental conditions
conducive to microbial activity (e.g., moisture, pH). The primary difference of the two technologies is that,
in aerobic bioreactors, the objective is to enhance the generation of CH4; whereas, in aerobic reactors, the
objective is to minimize CH4 generation. Both methods utilize leachate recirculation as a means to control
and enhance moisture levels within the landfill. Leachate recirculation has been performed for a number
of years primarily as a means to economically manage the leachate.
Data are presented in Table 3-1 on leachate disposal costs developed from a case study of a landfill in
Georgia (Darragh, 1997). Initially, the leachate was hauled to an off-site treatment facility; however, the
facility began experiencing treatment problems that were attributed to the leachate. The leachate was then
hauled to a larger treatment facility for a period of time before odor problems forced consideration of other
alternatives. The data in Table 3-1 are based on average annual costs projected over a 20 year time frame.
Costs for equipment, labor, transportation, and maintenance are included (Darragh, 1997).
Table 3-1. Leachate Disposal Costs for a Case Study in Georgia
Method Cost ($/gal)
Total Recirculation 0.011
Off-Site Treatment 0.090
On-Site Treatment with Rochem® 0.042
On-Site Treatment with Vacom® 0.037
Reference: Darragh, 1997.
Another leachate recirculation demonstration project was recently completed at the Roosevelt Regional
Landfill in the State of Washington. The objectives of this project were to add 35,000 to 50,000 gallons of
leachate and/or water per 1,000 tons of solid waste, maintain less than 12 inches of leachate head over the
bottom liner, observe whether the recirculation of large amounts of leachate causes large increases in
leachate generation, and, to a lesser extent, determine whether other operational or environmental problems
would be encountered [Regional Disposal Company (RDC), 1997].
The demonstration area covered two acres of in-place solid waste of approximate 60 foot depth. Between
October 1996 and March 1997, RDC added over 7,000,000 gallons of leachate to the demonstration area
which was equivalent to about 50,000 gallons per 1,000 tons of waste. RDC installed a pipe below the
demonstration area to observe leachate head on the bottom liner. Through September of 1997, no leachate
head build-up has been observed (RDC, 1997). Further, RDC estimated that the total amount of moisture
needed to reach field capacity for the Roosevelt demonstration project is 87,000 gallons per 1,000 tons of
waste. No significant operational or environmental problems were encountered. The production or quality
of LFG generated during the demonstration was not monitored. In addition, data on leachate quality specific
to the test area were not gathered (RDC, 1997).
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3.1 Operation of Landfills as Anaerobic Bioreactors
3.1.1 Introduction and General Overview
As mentioned above, the objective of operation of landfills as anaerobic bioreactors is to accelerate waste
decomposition and gas generation by control of moisture, pH, temperature, and nutrients. Methods to
enhance the collection efficiency of LFG may also be incorporated into an anaerobic bioreactor design. Of
the control parameters, moisture is considered the most critical (Yolo County, 1997). Gas generation during
conventional landfilling techniques occurs over long periods of time (more than 30 years). Over the lifetime
of the landfill, CH4 generated during the early stages (i.e., before extraction wells are in place) and late
stages (i.e., when economic recovery is no longer possible) is typically not recovered. Further, final clay
covers can be quite porous which limits the amount of CH4that can be collected.
Leachate recirculation is an important aspect of anaerobic bioreactors for moisture management and, as
described above, can provide significant economic benefits. Additional benefits of anaerobic bioreactors
include improved leachate quality, reduced costs for post-closure gas and leachate management, and
problems related to long-term settling (subsidence). In addition, bioreactors can potentially provide
additional revenue to the extent that enhanced subsidence during the active phase of the landfill offers
additional volume for waste emplacement.
Another important aspect that can be incorporated into the design of an anaerobic bioreactor is a gas-
impermeable (synthetic) membrane. These membranes, when installed over gas conducting layers (e.g.,
shredded tires), can achieve essentially 100 percent LFG collection efficiency. However, use of synthetic
membranes alone (i.e., without moisture management) will likely result in degradation and gas generation
rates much slower even than conventional landfills (Yolo County, 1997).
Early work on anaerobic bioreactors began in the mid-1980's during tests on six cells at a landfill in Mountain
View, California. These tests showed gas generation rates three to five times that of conventional landfills
in the area. Other tests have occurred since; however, data on gas generation are lacking. One of the test
programs did show improvements to leachate quality. The following sections describe a pilot project
conducted at the Yolo County Central Landfill (YCCL) which was designed to fill the knowledge gaps
remaining from previous work on anaerobic bioreactors.
A description of a demonstration project being conducted in Yolo County, California is given in the following
section. Although this project involves aspects of landfill construction that may be limited to consideration
for new landfill cells, the EPA is aware of a project just underway where similar operating practices are being
used on an existing landfill in Washington State. Unfortunately, details of this project were not available as
of the preparation of this report.
3.1.2 Yolo County Central Landfill, California
The pilot project at YCCL consists of two test cells of approximately 9,000 tons of waste each (solid waste
and green waste). An "enhanced" test cell is being operated as an anaerobic bioreactor, while the other test
cell is serving as the "control" cell. Both cells are constructed to be gas-tight and are fitted with sensors to
monitor moisture and temperature at multiple points within the waste. Characteristics of the enhanced and
control cells are as follows (Augenstein et al., 1997):
33
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Control Cell Enhanced Cell
Area (acres) 0.27 0.27
Average Depth (ft) 40 40
Solid Waste (tons) 7,283 7,133
Alternative Daily Cover - Green Waste 1,454 1,336
(tons)
Average Compaction (Ib/cubic yard) 1,014 1,027
Shredded Tires Used (tons) 200 295
A diagram of the YCCL Anaerobic Bioreactor Demonstration Project is shown in Figure 3-1. This figure
shows the leachate recirculation system of the enhanced cell, including the leachate reinjection (distribution)
manifold injection pits. Objectives of the project include:
• substantially accelerate LFG generation and maximize gas capture;
• monitor biological conditions within the test cells;
• provide technology transfer;
• gain a better understanding of moisture movement within the landfill; and
• assess the performance of shredded tires within the landfill as a medium for gas transfer.
Construction, filling, and covering of the test cells was completed in December 1995. Addition of liquid to
the enhanced test cell was begun in October 1996. Table 3-2 contains data on the liquid balance of the
enhanced cell. As shown in the table, the apparent minimum field capacity of moisture per weight of dry
waste was estimated to be 113 gal/dry ton or 46 percent (Augenstein et al., 1997).
Table 3-2. Enhanced Cell Moisture Balance
Parameter
Incoming Waste (20 percent moisture assumed)
Supplemental Liquid Added
Recycled Leachate
Total Liquid Input
Generated Leachate
LFG Condensate
Emitted Within LFG
Total Liquid Output
Apparent Field Capacity (179 to 66.2)
Volume (gal/dry ton
waste)
60
55
64
179
64
0.2
2
66.2
113 (90 gal/as-placed ton)
34
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cn
40MILLLDPEGEOMEMBRANE
1.5'OF COMPACTED CLAY
120ZGEOTEXTILE 1.0'OFADC
2.0'OF UNCOMPACTED SHREDDED
TIRES, 1.0' AFTER COMPACTION
f O ELECTRIC PUMP
Figure 3-1. Anaerobic Bioreactor Demonstration Project at YCCL
(adapted from Augenstein et al., 1997)
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Data on leachate quality are presented in Table 3-3. These data represent changes in leachate chemistry
following approximately eight months of leachate recirculation. Due to the limited amount of leachate
collected from the control cell and the manner in which it is collected (leachate was in contact with the
ambient air for long periods of time prior to sampling), the leachate chemistry from the control cell can not
be compared to the data in Table 3-3 (Augenstein et al., 1997).
Table 3-3. Changes in Leachate Quality for the Enhanced Cell
Parameter
pH @ 25 °C
BOD (mg OJL)
COD (mg OJL)
TDSs@180°C(mg/L)
TOC (mg/L)
Iron (micrograms/L)
Manganese (micrograms/L)
Calcium (mg/L)
Toluene (micrograms/L)
During Initial
Recirculation
5.8
5,020
20,300
19,800
9,830
152,000
41,900
1,400
160
After 4 Months
Recirculation
7.0
820
2,860
7,600
611
933
4,000
480
75
Note: BOD = Biological Oxygen Demand, COD = Chemical Oxygen Demand, O2= Oxygen,
IDS = Total Dissolved Solids, and TOC = Total Organic Carbon.
Data on LFG recovered from the enhanced and control cells are presented in Table 3-4. From January 1997
to July 1997, average LFG flows in the enhanced cell were over 30 percent higher than the control cell with
slightly higher CH4 content. In addition, settling in the control cell was only 30 percent of the enhanced cell
(Augenstein et al., 1997). Figure 3-2 is a graph comparing cumulative LFG and CH production in the
enhanced and control cells.
Table 3-4. LFG Summary Data for the YCCL Demonstration Project
Parameter
Cumulative LFG Volume, 7/96 - 7/97 (106scf)
Average LFG Flow Rate (scfm)
Average CH4 Content (%)
Average Landfill Settlement, 5/96 - 5/97
(inches)
Control Cell
9.0
27
50
4.3
Enhanced
Cell
12.2
39
53
14
36
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1000
900
an of Vacuum (October 16, 19U6)
of Licuidto Enhanced Ce
-Control Total Landfill Gas
Enhanced Total Landfill Gas
-Control Total Methane
Enhanced Total Methane
Time (Month-Year)
Figure 3-2. Cumulative LFG and CH4 Production for the Control and Anaerobic Bioreactor Cells
(adapted from Augenstein et al., 1997)
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In addition to LFG generation, temperature trends in the enhanced and control cell are of interest. Soon
after waste emplacement was completed, temperatures deep within both cells increased by approximately
6 to 10 °C. This initial trend is attributed to the methods of waste emplacement. Heat from initial aerobic
activity is thought to have been captured by quick vertical filling of the cells and insulation from the ambient
air (Yazdani, 1997). Over approximately the next 16 months, the refuse temperatures slowly decreased to
about 40 °C. In the upper layers of both cells. Finally, as of February 1997 (approximately four months after
liquid addition began in the enhanced cell), refuse temperatures within the enhanced cell have begun to
climb while temperatures in the control cell have remained essentially constant (Yazdani, 1997).
3.1.3 Emissions and Costs
Costs for the YCCL pilot project are shown in Table 3-5. Costs include construction of both the enhanced
and control test cells. Projections were made for the application of the technology on a new 22-acre waste
management unit. The landfill unit would have a 58 ft depth and would receive between 450 and 500 tons
of waste per day. Large differences were seen in capital costs depending on whether or not a double-lined
containment system would be required. Some states are expected to require dual-liners, since liquid
(recirculated leachate or H2O) will be added to the landfill. Construction costs for double-lined containment
systems were estimated to be $50,000 to $100,000 per acre higher than single-lined systems (Yolo County,
1997).
Table 3-5. Costs for the YCCL Anaerobic Bioreactor Pilot Project
Item Cost ($)
Base Liner 114,000
Clay Levees 120,000
Waste Monitoring System 40,000
LFG Collection System 34,500
Leachate Recirculation System 47,500
Cover System 52,000
Initial Operation and Testing 7,000
Project Design 73,000
Reporting 25,000
Contingencies 50,000
Total Costs 563,000
Financial support for construction of the YCCL Bioreactor Project was received from the California Energy
Commission, Yolo County, Sacramento County, and the California Integrated Waste Management Board.
Cost components for the project are broken out in Table 3-5. The monitoring phase of the project (1996 to
1998) is being financially supported by the U.S. DOE's Western Regional Biomass Energy Program and
Urban Consortium Energy Task Force, as well as Yolo County (Augenstein et al., 1997). The total costs
associated with the two year monitoring phase are $275,000 (these costs include O&M costs and technology
transfer activities).
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No data were available for estimating the costs of utilizing the anaerobic bioreactor process on existing
landfills. For existing landfills, the technology could be considered at sites with a minimum single-liner
containment system (e.g., in areas with deep groundwater). In areas where the depth to groundwater is low,
the process should probably be limited to existing landfills with dual-liner systems. State or local regulatory
agencies should be consulted regarding the suitability of this technology in any area.
Over the life of the landfill, application of the anaerobic bioreactor process will result in lower emissions of
CH4, NMOC, and other LFG constituents. As described above, this is due to more efficient LFG collection
over a shorter time-frame and the fact that the waste is stabilized much sooner than with conventional landfill
methods. Although the impacts are thought to be significant, data are not currently available to accurately
quantify these benefits.
3.2 Operation of Landfills as Aerobic Bioreactors
3.2.1 Introduction and General Overview
As with anaerobic bioreactors, the operation of landfills as aerobic bioreactors involves maintaining sufficient
moisture within the waste mass to promote biologic activity. However, in aerobic bioreactors, oxygen (from
air) is continually added to the system to maintain an environment conducive to aerobic degradation of
wastes. Some of the advantages of operating a landfill as an aerobic bioreactor include (Gordon et al.,
1997):
• biodegradation rates up to 40 times faster than occur in anaerobic environments (i.e.,
accelerated waste stabilization);
• decreased solubility of metals leading to lower migration via leachate (also seen in
anaerobic bioreactor processes, as shown in section 3.1.2);
• significant reduction in CH4 production;
• reductions in odor (i.e., due to reduction in emissions of reduced sulfur compounds); and
reduced leachate volume and strength [e.g., chemical oxygen demand (COD), biological
oxygen demand (BOD)].
By increasing the rate of biodegradation, waste volume is reclaimed over a shorter period of time (estimates
are less than 5 years). For a given volume of landfill space, this offers the potential for the addition of more
waste to the space during the active life of the landfill. The economic value of this additional landfill space,
the low cost of the technology, and the avoided costs of at least some leachate treatment or disposal are
the key benefits for this technology.
Aerobic bioreactor technology has been in use in Japan, where land value is extremely high, for many years
(Hanashima et al., 1989). More rapid landfill reclamation and improvements in leachate quality have been
noted as the most important achievements. The technology is expected to become a prime candidate
technology for landfills in the U.S. and elsewhere that can not generate LFG in sufficient quality or quantity
to economically recover the associated energy. As seen in Japan, it may gain additional importance in areas
where landfill space carries a premium value. In addition, this technology could also be considered as a
follow-on technology for energy recovery projects at landfills that are no longer producing CH 4 at
economically valuable levels.
39
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3.2.2
Baker Place Road Landfill, Columbia County, Georgia
American Technologies Inc. (ATI) was contracted by the Southeastern Technology Center (STC) to pilot test
an aerobic bioreactor at the Baker Place Road Landfill in Columbia County, Georgia. STC funded the pilot
test through a cooperative agreement with the DOE. Testing began in January 1997 on 8 acres of the active
16 acre landfill cell. Early results after five months of operation have shown an increase in aerobic activity
(e.g., increase in landfill temperature, decrease in CH4content of LFG), and the pilot test has been extended
into 1998 to collect additional data on landfill settlement (Hudgins, 1997). A simplified schematic of an
aerobic bioreactor system is shown in Figure 3-3.
Air
Blowers
Temporary Cover System
^YTTTTTi
( (' ( (s^ni^arjf W(a4e ( ( ( (
\ \ \ \ 1 ^ \ \ \ \ \ \ ^
I | I I I ! I I I I [ I I
Leachate
Pump
Figure 3-3. Aerobic Bioreactor System Schematic
As shown in Figure 3-3, an aerobic bioreactor system can utilize the existing leachate collection system
supplemented by air injection wells to facilitate the proper balance of air flow, moisture, and temperature
control (Hudgins, 1997). The entire system consists of the leachate collection/air injection piping, air
blower(s), leachate holding tank (not shown), leachate injection pump/piping, and monitoring equipment
(e.g., for waste mass temperature and moisture). Leachate is injected into the landfill through an
intermediate clay cap to the top of the waste. Delivery of air and water are balanced to obtain optimal
conditions for degradation. Improper balancing of air and water can lead to elevated waste mass
temperatures and landfill fire potential. After completing aerobic decomposition on a lift of waste, the
leachate injection system can be removed and placed on top of a new lift of waste, minimizing material
costs.
As mentioned above, early results of the project showed an increase in temperature and a decrease in CH4
production. Figure 3-4 shows the evolution of LFG composition during the first 50 days of operation while
the landfill environment was being transformed from an anaerobic environment to a predominantly aerobic
environment. The data for Figure 3-4 were taken at a single monitoring point typical of the overall landfill
(Hudgins, 1997).
Early results also included reductions in leachate BOD (more than 65 percent), metals (more than 75
percent), and organics (more than 75 percent). At the onset of the project, approximately 120,000 gallons
per month of leachate was being collected from the landfill. For the first six months of the project, all of the
leachate was returned to the landfill. By the seventh month, some excess Hp was being held in a holding
tank. ATI anticipates that, at some point in the future, the net amount of leachate will exceed that which is
returned to the landfill requiring some off-site treatment (Hudgins, 1997).
40
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3.2.3
Emissions and Costs
Net emissions of CH4 and VOC will be reduced, potentially at the levels described above or shown in Figure
3-4, assuming that gas generation rates have remained relatively constant (i.e., these data are concentration
data and no flow rate data were available to generate mass emission rate estimates). CO 2emissions will
increase as CH4 and NMOC decrease. However, since CH4 is a much more potent GHG than CO2, net GHG
impacts will decrease. Depending on the characteristics of the leachate and how it is stored, the holding
tank could become a source of NMOC emissions.
20
10
MN-~""W
1/10/97 1/30/97 2/19/97 3/11/97 3/31/97 4/20/97 5/10/97 5/30/97 6/19/97 7/9/97 7/29/97
Date
Figure 3-4. LFG and Waste Temperature Measurements Obtained During the
First Six Months of an Aerobic Bioreactor Operation
Capital costs for an aerobic bioreactor system are estimated to be about $25,000 to $30,000 per acre
(average 10 foot depth) based on the Baker Road Landfill Project (Hudgins, 1997). It is assumed that a
leachate collection system is already in place and that this system is capable of delivering air to all portions
of the landfill. Costs would be higher where no leachate collection system is in place or where additional
air injection wells are needed to introduce air throughout the landfill. Capital costs include the costs of air
blower(s), leachate holding tank, leachate injection pump and piping, and monitoring equipment. No
41
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information was available on O&M costs, however these will be similar to those for operating and
maintaining a gas collection system plus some additional costs for landfill monitoring.
A physical survey was planned for Fall 1997 to determine the extent of landfill settling during the first ten
months of the project. Estimates have been made that an additional $5,000,000 in revenue (from additional
disposal fees) could be generated if 25 percent reduction in waste mass for the entire 16 acre cell could be
achieved with an aerobic bioreactor (Darragh, 1997). Additional savings relative to the avoided costs of
leachate treatment over an assumed ten year landfill life (as an aerobic bioreactor) could reach over
$350,000, assuming that the average leachate production is 200 gallons per acre per day and that on-site
treatment has a net cost of $0.03 per gallon ($0.04 for on-site treatment to $0.01 for recirculation).
Closure costs are likely to remain the same using either conventional waste management techniques or
operation as an aerobic bioreactor, since, for new landfills, liners will still be required to meet Resource
Conservation and Recovery Act Subtitle D requirements. Assuming that emission levels following the
aerobic bioreactor process are below permit levels, a gas collection system will not be needed; however,
gas vents or other gas control features will still be needed to allow venting through the cover system.
Additional savings are expected relative to reduced post-closure groundwater/leachate sampling and post-
closure leachate treatment (Darragh, 1997).
3.3 Production of Methanol from LFG
3.3.1 Introduction and General Overview
Conversion of LFG to methanol for use as a vehicle fuel or as a chemical feedstock has been investigated
in the U.S. since the early 1980s. These early investigations concluded that methanol production from LFG
was technically feasible; however, only marginal economic returns were expected with the pricing of
methanol during that time [International Harvester Company (IHC), 1982; Science Applications, Inc., 1983].
However, during the early 1990's, the price of methanol increased substantially (2 to 3 times) due to the
reformulated gasoline (RFC) requirements of the Clean Air Act Amendments of 1990 (Taylor, 1994).
Methanol or its derivative, methyl tertiary butyl ether (MTBE), are prime candidates for use as oxygenates
in RFC. Methyl tertiary butyl ether is currently being used in many RFC formulations in U.S. ozone
nonattainment areas.
Methane conversion to methanol is conducted in a gas reformer at an elevated pressure and temperature
in the presence of steam and a catalyst (e.g., nickel). When CH4and steam come into contact with the
catalyst, two reactions occur (IHC, 1982):
C#4 D H20 - 3H2 D CO (reaction 1)
H2O D CO ^ H2 D CO2 (reaction 2)
Varying amounts of the reactants and products exist from the two equations depending on reaction
conditions. The resulting gas, which is a mixture of all of these species, is referred to as synthesis gas (syn-
gas). The syn-gas is then fed into a methanol catalyst and reactor system to form methanol by the following
two reactions (IHC, 1982):
CO D 2H2 ^ CH3OH (reaction 3)
CO2 D 3H2 * CHjOHD H2O (reaction 4)
42
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An LFGto methanol conversion plant was proposed for start-up in the Spring of 1996 by TeraMeth Industries
(TMI). This facility was to have been located in West Covina, California; however, the project was never
constructed. Details on why the project was abandoned are not clear, but are apparently related to local
permitting issues (Wuebben, 1997). TMI has completed permitting fora facility in the State of Washington
and plans on construction to begin by the end of 1997.
Figure 3-5 shows a simplified process flow diagram for a methanol production facility. The process can be
divided into four separate components:
1. Pretreatment. As with most other LFG utilization technologies, it is necessary to remove contaminants
such as reduced sulfur compounds and halides. The pretreatment section of the process includes
equipment for desulfurization, condensation, desiccation, halide removal, and CO2 extraction.
Significant pretreatment of halides and sulfur compounds (i.e., low ppbv levels) is necessary to reduce
the potential for catalyst poisoning in the reformer.
2. Reforming. Following gas cleanup, the LFG is sent to a catalytic reformer where reactions 1 and 2, on
the previous page, take place (to produce syn-gas). The syn-gas is then separated from condensate,
and the H2O is recycled back to the reformer.
3. Conversion. The syn-gas is compressed prior to entering the methanol converter where reactions 3 and
4, on the previous page, take place.
4. Purification. The liquid from the methanol converter is then distilled. Methanol from the top of the
distillation unit is sent on to storage tanks, while the Hp and byproducts are recycled back to the
reformer.
Sulfur compounds, halides, H2O,
NMOC, some CO2
Raw LFG
Pretreatment
CH4,
Reforming
H2O and
byproducts
H2O
Methanol
product
Purification
CH3OH
(Raw methanol)
H2, CO, CO2
(Syn-gas)
Conversion
Figure 3-5. Simplified Process Flow Diagram of a LFG to Methanol Plant
43
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LFG has been proposed for producing U.S. Grade A methanol that could be used as a chemical feedstock
or as a vehicle fuel or fuel additive. Methanol is used in the production of many intermediate chemicals
including formaldehyde, acetic acid, and methyl amines. End products which are manufactured from
methanol-derived intermediates include plastics, disinfectants, adhesives, insecticides, and solvents.
3.3.2 Emissions and Costs
Estimates of emission reductions based on mass balance procedures for the proposed southern California
project are given in Table 3-6. These data are taken from an air quality impacts assessment performed by
SCAQMD (SCAQMD, 1994). The data summarized in this table compare the emission reductions
associated with the proposed LFG to methanol conversion process to the emissions created by the same
amount of flared LFG (3.6 million scfd).
Table 3-6. Air Emission Impacts for a Proposed LFG to Methanol Plant
Net Emission
Reductions
Ib/day
tons/year
CO
272
49.6
voc
12.1
2.2
NOX
68
12.4
Pollutant
sox
17.0
3.1
PM10
74.0
13.5
CO2
373,964
68,248
CH4
1,479
270
Adapted from SCAQMD, 1994.
Emissions from the proposed process included NMOC emissions following gas clean up and destruction
in the catalytic reformer (see Figure 3-5) with an estimated destruction efficiency of 99.5 percent. The
difference in CO2 emissions is due to consumption of CO2 during pretreatment of the LFG and during
formation of methanol from the syn-gas (see reactions 1 through 4 in section 3.3.1). Emissions of sulfur
dioxide (SO^ are reduced due to removal of sulfur-containing compounds during pretreatment. The
reductions in NMOC and NOX are determined based on vendor-guaranteed values for destruction efficiency
and NOX formation for the reformer.
Additional air quality benefits would be expected if some or all of the methanol produced by the facility is
used as vehicle fuel. The SCAQMD estimated that, compared to gasoline engines, methanol powered
vehicles would emit 30 to 50 percent less ozone-forming emissions (i.e., NMOC and NO) and reduce toxic
emissions by 50 percent (Wuebben, 1991).
To the extent that dioxins and furans and combustion products are emitted via flaring, the LFG to methanol
conversion process has the potential to reduce these emissions. Since only a small amount of the LFG used
by such a methanol facility would be combusted (to heat the catalytic reformer), most of the LFG would no
longer be flared (and the accompanying combustion products would not be emitted).
Few data are available for actual capital and operating costs for LFG to methanol plants. In a 1982
feasibility study for the State of New York, IHC estimated the capital costs for installing and start-up of a 6.7
million gallons per year Grade C methanol facility to be $14.9 million (over $17 million in 1997) for a
modular-constructed (versus field-constructed) plant (IHC, 1982). Conversely, data provided by TMI for their
West Covina facility provided capital costs of $9.4 million (Bonny, 1994). This facility's capacity was to be
approximately 6.1 million gallons per year of Grade A methanol (highest purity), and the plant was also to
be constructed in a modular fashion. The reason for the large discrepancy between these estimates was
not apparent from available data sources.
44
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Operating costs quoted for a plant in the IHC study were $1.9 million (about $2.2 million 1997 dollars). The
operating costs, in terms of methanol produced, were estimated at $95/ton (about $110 in 1997 dollars; IHC,
1982). No comparable data were available for the proposed southern California facility.
3.4 Production of Commercial CO2from LFG
3.4.1 Introduction and General Overview
Most LFG utilization technologies do not attempt to capture the CO2component of LFG (LFG CO^ for
commercial use. Hence, the commercial value and environmental benefits associated with LFG CO2
recovery are not realized from these projects. The value of recovering the energy associated with CH4 from
landfills has been discussed in previous sections. However, since CO2typically makes up 30 to 50 percent
of LFG, there may also be merits associated with its recovery as a commercial product.
A study on the feasibility of LFG CO2 recovery prepared by Acrion Technologies, Inc. (Acrion) for DOE
indicated an increasing demand for high purity (food grade) liquid CO2(Acrion, 1992). In 1992, domestic
sales were estimated to be 11,000 tpd and the historical growth rate was cited as 8 percent. Retail prices
for high purity liquid CO2 were stated to be between $50 and $200 per ton depending on volume and delivery
point (transportation is the key driver of cost for CO^ Domestic landfills were estimated to be able to supply
twice the current CO2 demand.
Current utilization technologies do not attempt to recover LFG CO2because: (1) recovery would require
recompression of the CO2 which is expensive; (2) trace contaminant removal to the purity requirements for
food grade CO2 cannot be performed by any single commercial process (Acrion, 1992); and (3) nontechnical
hurdles, such as the public's perception of a food product developed from LFG.
The objectives of Acrion's process are to simultaneously recover fuel grade CH4(LLG) and food grade CO2
from raw LFG. A simplified flow diagram of the Acrion process is shown as Figure 3-6. The process
consists of the following four steps (Acrion, 1992):
1. Compression, inter-cooling, and H2O removal is performed as with the other utilization options during
LFG preparation.
2. CO2 is condensed from the dried, chilled LFG at elevated pressures in a refluxed absorber column. In
this step, the trace contaminants are absorbed by the liquid CO2
3. The overhead vapor from CO2 condensation contains more than 80 percent CH4, along with nitrogen,
and CO2. The residual CO2 is removed with a conventional solvent. The vapor is condensed by
refrigeration to produce the LLG product.
4. Purified (food grade) CO2 is produced by triple-point crystallization (TPC). TPC is the formation of solid
CO2 in the presence of both liquid and vapor phases at temperature and pressure conditions near the
triple point of CO2 ("67 °F, 75.1 psi). Lowering the pressure slightly below the triple point pressure causes
the liquid CO2to boil: that in turn cools the TPC chamber. This internal cooling causes solid crystals
of CO2 to grow that exclude contaminants. Trace contaminants that were not removed earlier in the
process are left in the liquid phase in the upper portion of the chamber (mother liquor), and are separated
from the pure solid CO2 that moves downward, melts at the bottom of the chamber, and is removed as
clean liquid product.
45
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CH4
Raw LFG
J
Compression
Drying
Cooling
Dry
Chilled
LFG
CO2 Condensation +
Trace Contaminant
Removal
H20
CO2+ Trace
Contaminants
> Engine Fuel
LLG
Purified
Liquid CO2
Contaminant-
Rich CO 2
to Flare
Figure 3-6. Flow Diagram for Converting LFG to LLG and Purified CO2
Acrion estimated that over 98 percent of the CH4in the LFG is recovered by the process. Approximately
15 percent of the recovered CH4 is consumed by engines to generate on-site power. About 70 percent of
the LFG CO2 is recovered as product. Most of the balance is lost in the fuel to the engines and as
contaminated liquid absorbent that is incinerated in the onsite flare. The CO2product is estimated to contain
approximately 1.5 ppm of total impurities that are present due to adherence of some of the mother liquor
in Step 4 (Acrion, 1992).
Acrion is also investigating a similar process that does not utilize the TPC purification portion of the process
to purify CO2 (Brown, 1997). This process uses cold liquid CC^ from the LFG to purify both the Chj, and CQ
product streams. Contaminants are concentrated in a separate stream of CO2 that is fed to an on-site flare.
According to Acrion, negotiations are nearing completion for a demonstration project at a site in the State
of New York.
3.4.2
Emissions and Costs
An adequate characterization of potential plant emissions has not been made. The two primary sources of
emissions at a facility such as the Acrion facility described above would be the power generation engines
and the facility flare. Information on costs was not available.
3.5
3.5.1
Use of LFG as a Supply of Heat and CO2for Greenhouses
General Overview
One application of LFG currently in operation at Topgro Greenhouses Ltd., Langley, BC is the use of LFG
as a fuel supply for heating a greenhouse (Hanson, 1997). In addition, the exhaust gas from one of two boilers
is diluted and injected directly into the greenhouse to enrich the CO 2 concentration for the purpose of
promoting plant growth. This type of application using natural gas or propane is typical for greenhouses.
46
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Although the use of LFG to provide heat for greenhouses is not new, this project, where LFG is used to provide
both heat and CO2 enrichment, is the first known of its kind.
The Topgro system using LFG for CO2 enhancement in greenhouses is the first known of its kind. Additional
details of this project are given below. It is also worth noting that plans are underway to utilize waste heat
and CO2 generated by the PAFC project described in Section 2.1 in a greenhouse to be located at the landfill
(Borea, 1997).
In February 1994, Topgro began utilizing LFG generated by the nearby Jackman Landfill as heating fuel.
The landfill is located approximately one mile from the greenhouse. Some minor modifications to the boiler
were necessary to burn "wet" LFG, such as a larger size burner head and stainless steel components. The
project was designed and constructed by E.H. Hanson Engineering Group Ltd., Delta, BC. Use of exhaust
gas as a CO2 supplement occurred approximately four months later, after source tests and a detailed analysis
confirmed that it posed no risk to the plants (Hanson, 1995, 1997).
LFG supplied to the Topgro greenhouse is composed of 35 to 55 percent CH 4and 65 to 45 percent CO2
Nitrogen is also present at between 2 and 22 percent. Additional CO2 is produced by the combustion of CH4.
A feasibility study was initiated to determine if the boiler exhaust gas could be safely utilized in the greenhouse
environment. It was determined that the exhaust gas contained approximately 9.9 percent, or 99,000 ppm
CO2 (the 45 to 65 percent CO2 in the LFG is diluted by the large amount of combustion air required). As only
1,000 ppm CO2is required in the greenhouse, significant dilution of exhaust gas is necessary (Hanson, 1995).
3.5.2 Emissions and Costs
As the key part of the CO2 enrichment feasibility study, there was concern that certain combustion products
could be harmful to plant life (e.g., SO^ However, initial test data confirmed that sulfur gases would not be
a problem, because sulfur, mainly as methyl mercaptan, was found to be present at low levels (i.e., 50 ppm
range). Resulting SO2 concentrations were calculated by Hanson and determined to be well below levels
harmful to plants (Hanson 1995).
In addition, a botanical consultant advised that the concentration of ethylene must be maintained below 100
parts per billion (ppb) in the greenhouse environment to avoid accelerated plant aging. Ethylene is present
in the unburned LFG at approximately 2.3 ppm. Based on source test data, the highest stack gas
concentration was found to be 0.4 ppm, indicating at least 83 percent destruction of ethylene in the combustion
process. Dilution of the stack gas brings the ethylene concentration well below the 100 ppb level, as
discussed below.
Source test data were collected for five boiler firing rates, from 10 to 90 percent. The stack gas data are
presented in Table 3-7. Prior to introduction into the greenhouse, stack exhaust gas is diluted with ambient
air (assumed 300 ppm CO^ to meet the required 1,000 ppm CO2 concentration. The concentrations of the
diluted mixture are presented in Table 3-8. Thus, as long as proper combustion is ensured, the ethylene
concentration of the diluted exhaust air will be well below the 100 ppb limit. All of the other contaminants
analyzed are also well within acceptable levels for plants and personnel.
Economic benefits for a landfill owner or operator are dependent on the price of LFG delivered to the
greenhouse. Pricing is often negotiated as a percentage of the local cost of natural gas or propane (on a
Btu basis). Hanson estimates that a project should be economically favorable if the landfill is within two to
three miles of the greenhouse (Hanson, 1997).
47
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Table 3-7. Concentrations of Exhaust Constituents
During LFG Combustion for CO2 Enhancement
Boiler
Firing
Rate (%)
10
16
39
70
90
C02
(%)
8.7
8.1
8.6
9.6
9.9
CO2 O2 O2 CO
(ppm) (%) (ppm) (ppm)
87,000 10.5 105,000 93.0
81,000 10.9 109,000 108.7
86,000 10.6 106,000 90.2
96,000 9.1 91,000 50.1
99,000 8.6 86,000 20.9
NOX
(ppm)
4.6
5.0
8.0
11.8
15.9
Ethylene
(ppm)
0.3
n/a
0.4
0.3
0.3
Table 3-8. Concentrations of Exhaust Constituents
Boiler
Firing
Rate (%)
10
16
39
70
90
Dilution
Rate
124
116
123
137
141
in Diluted Make-Up Air to Greenhouse
C02 02 CO
(ppm) (%) (ppm)
1,000 20 0.75
(approx.)
1,000 " 0.94
1,000 " 0.73
1,000 " 0.37
1,000 " 0.15
NOX
(ppm)
0.04
0.04
0.07
0.09
0.11
Ethylene
(ppb)
2.41
n/a
3.26
2.19
2.12
48
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4.0 POTENTIALLY APPLICABLE TECHNOLOGIES (TIER 3)
While some landfills can generate large quantities of gaseous pollutants, most generate only small amounts
sufficient to support comparatively small power generation projects (300 to 1,000 kW). Traditional energy
utilization technologies may not be cost-effective alternatives for conversion of LFG into useable energy at
these small landfills, or may be difficult to permit due to their significant NO „ CO, and VOC emissions (e.g.,
RIC engines). For landfills already using (permitted) flares for controlling LFG emissions, it may not be
desirable to eliminate this type of control, but rather retrofit utilization equipment in order to take advantage
of waste heat. In both of these situations, the Stirling engine and/or ORC may have potential applicability.
A study sponsored by the Coalition of Northeast Governors (CONEG) (SCS Engineers, 1997) examined the
use of several emerging technologies for energy conversion using LFG, including the Stirling engine and
ORC. Operating data and costs were estimated based on conceptual design information or, in the case of
ORC, use in geothermal applications, as no operating experience is available at landfills.
This section describes the applicability of using these emerging technologies for energy conversion from
LFG. The research documented here is primarily based on general historic information and cycle descriptions,
discussions with experts, extrapolation of operating and cost data from other applications, and engineering
judgement.
4.1 Stirling Cycle
4.1.1 History and Cycle Description
The Stirling engine was invented in 1816 by Robert Stirling. Stirling's design was the first closed-cycle "hot
air" engine. The cycle deals mainly with the regenerator principle, which is a means to reuse heat that would
otherwise be wasted (Ross, 1981). An early Stirling-design engine was used to pump H p from a quarry
in Scotland in 1818. In 1843, a steam engine was converted using the Stirling principle. Unfortunately, early
use of the Stirling engine was hampered by two main factors: (1) the need for high operating temperatures
(approximately 1,292 °F) caused material degradation problems, because heat resistant materials (e.g.,
stainless steel) were not yet available, and (2) competition from higher-power, more versatile spark-ignition
and diesel engines (MTI, 1986).
In the Stirling engine, power generation is accomplished by compressing cool gas (working fluid) and
expanding it when hot, a process common to most heat engines. The Stirling engine can be visualized as
a cylinder with a piston at each end; between the pistons is a regenerator. Two main types of Stirling engines
are shown in Figure 4-1, each has two variable-volume working spaces filled with the working fluid- one
for expansion and one for compression of the gas (Avallone and Baumeister, 1989). In the Stirling engine,
gas is contained in a continuous, closed volume that is divided into hot and cold regions. The size of the
volume is periodically varied to compress and expand the gas. Heating and cooling are accomplished by
periodically transferring working gas between the hot and cold regions (MTI, 1986). Since the engine derives
its heat from an external source, almost any type of fuel or combustible material can be used.
49
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Heot exchonger
Compression space
(Heot rejected)
Expansion space
theal absorbed)
Displocer.
Compression
space (heat
rejected)
Regenerator
Working piston
Working piston
Power input or output
at cronkshoft
Heat
exchanger
Power input or output
at cronkshoft
Double
Single cylinder,
cylinders,
two piston engine
piston plus displacer
Figure 4-1. Stirling Engines
(© Copyright 1989. The McGraw-Hill Companies. Reproduced with Permission.)
4.1.2
Current Usage
Extensive research has been devoted to the development of Stirling engines for space power systems (using
solar energy) and for use in automobiles. Today, there are no commercially available Stirling engines,
although several manufacturers are hopeful to develop commercially viable units for industrial and automobile
use (up to 100 kW) to small units (2.5 kW) to very small household units (0.5 kW) for areas of the world with
very high energy costs.
Major research and resources have been directed at development of an automotive Stirling engine (ASE).
The ASE program was underway at Mechanical Technology Incorporated (MTI) in Latham, New York, from
1978 until 1990, when funding ceased (Hicks, 1997). This program, sponsored by the DOE, and administered
by the National Aeronautics and Space Administration's Lewis Research Center, was intended to "successfully
integrate the Stirling engine into an automobile with acceptable drivability" (MTI, 1986). Adaptations of the
ASE application include use in generator sets, irrigation pumps, solar electric units, heat pumps, industrial
prime movers, submarines, and farm equipment. The ASE program concluded in 1990, and the automotive
version of the Stirling engine has yet to be used by the American automobile industry. However, another
company, Stirling Thermal Motors (STM), in Ann Arbor, Michigan, is presently actively developing a Stirling
engine for commercial use in automobiles, as another low-pollution alternative to electric vehicles.
4.1.3
Potential for Use with LFG
In theory, the Stirling engine is adaptable for use with LFG. Its advantages are high efficiency and low
emissions, compared to RIC engines (other advantages normally associated with Stirling engines, such as
quiet operation, are not as important in an LFG application).
CH 4 recovered from LFG can be used as an
50
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external combustion fuel to heat the working fluid (e.g., hydrogen is used in the ASE). Unfortunately, all recent
research related to Stirling engines has been focused on small-sized engines, from less than 2.5 kW
(Sunpower, Inc.) to about 100 kW (Mil's ASE engine, STM). Currently, no research is underway to develop
a larger Stirling engine that could be used in an LFG application (greater than 300 kW).
4.1.4 Emissions and Costs
Emissions from a Stirling engine in an LFG application would be associated with the external combustion
source (i.e., NOX, VOC, CO, and CO2). Virtually no emissions would be generated by the engine itself because
it is a closed cycle.
Since no Stirling engine greater than 100 kW has been manufactured for commercial use, costs associated
with the installation of a larger Stirling engine needed fora LFG application could not be ascertained from
available literature. Significant costs to consider include the purchase, operation, and maintenance of not
only the engine itself, but also the high-temperature (external) heat system. One expert doubts that a larger
Stirling engine (or group of engines) could be cost-effective compared to gas turbines or RIC engines, in a
LFG application (Beale, 1997).
4.2 Organic Rankine Cycle Engine
4.2.1 History and Cycle Description
An "ideal" (i.e., neglecting any energy losses) Rankine cycle is typically used to compare the performance
of actual steam engines and steam turbines. The ORC is a process that uses an organic fluid (rather than
steam) in a closed cycle to convert thermal energy into mechanical energy. The advantages of an ORC over
a steam Rankine cycle are as follows: (1) Depending on the type and boiling point of the organic fluid chosen,
the organic fluid will completely vaporize at a much lower temperature and pressure than steam, thus
eliminating steam system problems (like turbine blade erosion caused by entrainment) and the need for an
economizer, superheater, or boiler drum; (2) organic working fluid is noncorrosive; and (3) the ORC is a closed
system which eliminates the need to continuously add fluid or pre-treat the fluid.
Perennial Energy, Inc. (PEI) of West Plains, Missouri, has developed a commercially available ORC that
uses waste heat from a flare, thermal oxidizer, or other combustor as a heat source (PEI, 1993). The process
flow for PEI's ORC is shown in Figure 4-2. In this system, the HC working fluid is held in a liquid state in the
storage tank. The fluid is moved from the tank, at an elevated pressure, to the PEI (proprietary) recuperator
for preheating. Next, the vaporizer, using the waste heat for an external source, heats and pressurizes the
fluid. The vaporized fluid is then routed through an expander (turbine) where the expansion of the fluid, from
high pressure to lower pressure, converts thermal energy into mechanical energy. The expanded fluid passes
through the PEI recuperator where it is used to preheat the cooler fluid coming from the storage tank. After
exiting the recuperator, the now saturated fluid passes through the condenser where it is converted back
to a liquid state, and then on to the storage tank to perpetuate the process. The working fluid currently used
by the PEI ORC is isobutane, but other organic fluids, such as propane, butanes, pentane, and toluene, may
be used.
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Waste Gas
Hot Exhaust
"Waste Gas"
Vaporizer
Isobutane Liquid
Storage
Power
Isobutane (gal)
Turbine Expander
Generator
Isobutane (L)
Condenser
PEI Recuperator
Isobutane (L)
4.2.2
Figure 4-2. Process Flow Diagram for PEI'S Organic Rankine Cycle System
Current Usage
The ORC is currently being used to generate electricity using geothermal power at a plant site operated by
Pacific Energy in Mammoth, California. This power plant comprises eight 10,000 hp turbines that each drives
5 MW generators. Hot (320 to 330 °F) geothermal Hp is used by a tube-and-shell heat exchanger to
vaporize the isobutane working fluid. According to PEI, the system performs well (Walker, 1997).
No current usage of an ORC in a LFG application was found in the literature or identified through contacts
with experts.
4.2.3
Potential for Use with LFG
The ORC may represent a technically feasible alternative for electrical generation using LFG; however, no
LFG pilot plant studies have been conducted or are planned for this technology. This may be due to
resistance to "new" technology (even though the technology has been operating successfully in other
applications) and current economic factors of electrical generation.
4.2.4
Emissions and Costs
As with the Stirling engine, emissions from an ORC in an LFG application would be associated with the
(external) combustion source (e.g., a flare), mainly NOX, VOC, CO, and CO2. Virtually no emissions would
be generated by the ORC itself, as it is a sealed system.
Since no ORC is currently utilized in a LFG application, costs associated with its use are considered to be
rough estimates only. A typical system would be expected to be a modular-type, with several skid-mounted
units. Electrical distribution, controls, and other operational equipment would be pre-installed and pre-wired.
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The capital cost for such an ORC unit in the 5 to 25 MW range including installation and start-up is estimated
by experienced sources to be in the range of $1,200 to $1,500 per kW (Conner, 1997; SCS Engineers, 1997).
Organic Rankine Cycle units are reputed to require limited maintenance, based on geothermal operating
experience. Assuming that maintenance requirements for LFG would be comparable to geothermal operation,
and based on comparison experience with RIC engines, a cost range is estimated by experienced sources
at 0.5 to 0.8 cents per kWh (Conner, 1997; SCS Engineers, 1997).
4.3 Molten Carbonate Fuel Cells
Molten carbonate fuel cells (MCFCs) use an electrolyte of lithium and potassium carbonate (see Figure 2-1)
and operate at temperatures of approximately 650 °C (1200 °F) compared to PAFCs (described in Section
2.1) which operate at about 200
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