SEPA
United States Air and Radiation EPA-430-R-001
Environmental Protection (6202-J) February, 2000
Agency
Technical and Economic
Assessment: Mitigation of
Methane Emissions from
Coal Mine Ventilation Air
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Technical and Economic Assessment:
Mitigation of Methane Emissions from
Coal Mine Ventilation Air
Coalbed Methane Outreach Program
Climate Protection Division
U.S. Environmental Protection Agency
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COALBED METHANE OUTREACH PROGRAM
The Coalbed Methane Outreach Program (CMOP) is a part of the U.S. Environmental
Protection Agency's (U.S. EPA) Climate Protection Division. CMOP is a voluntary program that
works with coal companies and related industries to identify technologies, markets, and means
of financing profitable recovery and use of coal mine methane (a greenhouse gas) that would
otherwise be vented to the atmosphere.
CMOP assists the coal industry by profiling coal mine methane project opportunities at the
nation's gassiest mines, conducting mine-specific technical and economic assessments, and
identifying private, state, local and federal institutions and programs that could catalyze project
development.
DISCLAIMER
This report was prepared for the U.S. EPA. This preliminary analysis uses publicly available
information. U.S. EPA does not:
(a) Make any warranty or representation, expressed or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this report, or that
the use of any apparatus, method, or process disclosed in this report may not infringe
upon privately owned rights; or
(b) Assume any liability with respect to the use of, or damages resulting from the use of, any
information, apparatus, method, or process disclosed in this report.
ACKNOWLEDGMENTS
This report was prepared under Environmental Protection Agency Contract 68-W5-0017 by
Alternative Energy Development, Inc. (AED) and AED's subcontractor, University of Utah,
Chemical and Fuels Engineering Department (U of U). The principal authors were Mr. Peter
Carothers of AED and Dr. Milind Deo of U of U. U.S. EPA gratefully acknowledges the
contributions of time and information cited in this report from several organizations including
BMP, MEGTEC, CANMET, Neill and Gunter, Chalmers University, Caterpillar, and Solar
Turbines.
Cover photo: Appin power plant, New South Wales, Australia. Courtesy of Energy
Developments Limited.
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TECHNICAL AND ECONOMIC ASSESSMENT:
MITIGATION OF METHANE EMISSIONS FROM COAL MINE VENTILATION AIR
CONTENTS
1.0 INTRODUCTION AND BACKGROUND 1
1.1 Global Importance of Ventilation Air Emissions 1
1.2 Range of Emissions from U.S. Mine Ventilation Sources 2
1.3 Barriers to Current Recovery and Use 2
1.3.1 Technical Barrier 1: Large and Costly Air Handling Systems 2
13.2 Technical Barrier 2: Low Methane Concentrations 3
1.3.3 Technical Barrier 3: Variable Flows and Changing Locations 3
1.3.4 Institutional Barriers 3
1.3.5 Commercial Barrier 3
1.4 Report Content 3
2.0 IDENTIFICATION OF APPLICABLE TECHNOLOGIES 5
2.1 Demonstrated and Emerging Technologies 5
2.2 Overview of Ancillary Use Technologies 5
2.3 Ancillary Use Process Descriptions 5
2.3.1 Combustion Turbines 5
2.3.2 Internal Combustion Engines 8
2.3.3 Other Ancillary Uses 10
2.3.4 Summary of Ancillary Uses 10
2.4 Principal Use Technologies 11
2.4.1 Thermal Flow-Reversal Reactor 11
2.4.2 Catalytic Flow-Reversal Reactor. 16
2.4.3 Summary of Principal Uses 18
2.5 Technical Considerations in Adapting Air Handling Systems to Mine
Ventilation Facilities 20
2.5.1 Impacts on Mine Ventilation System 20
2.5.2 Integration With Fans Operating Within Oxidizer Systems 20
3.0 TECHNICAL EVALUATIONS 21
3.1 Numerical Modeling 21
3.1.1 Assessment Methodology 21
3.12 Thermal Flow-Reversal Reactor 21
3.13 Catalytic Flow-Reversal Reactor. 22
3.14 Pressure Drop 23
3.2 Technical Assessment Summary 24
3.2.7 Catalytic Flow-Reversal Reactor. 24
3.2.2 Thermal Flow-Reversal Reactor 24
4.0 PRACTICAL METHODS FOR USING ENERGY RECOVERED FROM
VENTILATION AIR OXIDIZERS 25
4.1 Heat Available for Recovery 25
4.2 Technical Issues Concerning Heat Exchangers 26
4.2.1 Embedded High-Temperature Heat Exchangers 26
4.2.2 Handling High Temperatures 27
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4.2.3 Placement 27
4.2.4 Maintenance 27
4.3 Energy Conversion Options 27
4.3.1 Direct Use of Thermal Energy 27
4.3.2 Electric Generation Using Steam Cycle 28
4.3.3 Electric Generation Using Gas Turbine 29
4.4 Allocation of Scarce Gob Gas: Flow-Reversal Reactor Versus Gas Turbine 32
4.4.1 Determine Efficiency Impact from Decreasing Turbine Inlet Temperature 32
4.4.2 Optimize Use of Scarce Gob Gas 33
4.4.3 Illustrative Example 33
4.4.4 Practical Implications 33
5.0 ACTUAL AND HYPOTHETICAL PROJECT CONFIGURATIONS 35
5.1 Ancillary Use of Ventilation Air 35
5.1.1 Partial Use of Ventilation Air in Internal Combustion Engines 35
5.1.2 Total Use of Ventilation Air in a Mine-Mouth Coal-Fired Plant 36
5.2 Principal Use of Ventilation Air 39
5.2.1 Project A. Principal Use of Ventilation Air in a Flow-Reversal Oxidizer with
a Gas Turbine Cogeneration Plant 40
5.2.2 Project B. Principal Use of Ventilation Air in a Flow-Reversal Oxidizer in a
Waste Heat Boiler Plant 43
6.0 CONCLUSIONS 47
6.1 Ancillary Uses 47
6.2 Technical Feasibility of the Principal Use of Ventilation Air without Supplemental Fuel 47
6.3 Economic Viability of Flow-Reversal Reactors 48
6.4 Impact of Carbon Credits 48
APPENDICES
Appendix A. Technical Evaluation of Ventilation Air Oxidation Processes
Appendix B. Industry Contacts
Appendix C. Sampling of Gas Turbine Models
Appendix D. Typical Spread Sheet Model for Allocation of Gob Gas
Appendix E. Illustrative Economic Models
Appendix F. CO2 Emissions Trading
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TABLES
Table 1. Summary of Differences and Similarities between the TFRR and the CFRR ....19
Table 2. Pressure Drops for CFRR and TFRR Processes Using Various Flow Rates,
Diameters, and Voidages 23
Table 3. Results of Sensitivity Analysis, Mine-Mouth Coal-Fired Plant 39
Table 4. Results of Sensitivity Analysis, Project A: Flow-Reversal Oxidizer with a Gas
Turbine Cogeneration Plant 43
Table 5. Results of Sensitivity Analysis, Project B: Flow-Reversal Oxidizer with a
Steam Plant 46
FIGURES
Figure 1. Schematic Flow Diagram of the Appin Project 9
Figure 2. Schematic of Thermal Flow-Reversal Reactor (TFRR) 12
Figure 3. Illustrative Ideal Temperature Profiles in TFRR 14
Figure 4. Illustrative Ideal Heat Exchange Medium Bed Temperature Profiles in TFRR ...15
Figure 5. Schematic of Catalytic Flow-Reversal Reactor (CFRR) 17
Figure 6. Percent of Energy Recovered as a Function of Methane Concentration in
Ventilation Air 25
Figure 7. Schematic of Cogeneration Option 30
Figure 8. Turbine Efficiency versus °F below Design Turbine Inlet Temperature -
Generic Case 32
Figure 9. Turbine Power Output at Various Gob Gas Allocations between the Flow-
Reversal Reactor and the Gas Turbine - Generic Case 34
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UNITS OF MEASURE AND ACRONYMS
Units of Measure:
Btu
cf
cfm
cfs
GJ
J
kPa
kW
kWh
kW(e)
kW(t)
m3
m3/d
m3/m
m3/s
mcfd
MJ/sm3
MW
MWh
M
mm
Mm3
mmBtu
mmcfd
Mt
psig
Acronyms:
CFRR
U.S. EPA
1C
IRR
TFRR
VOCs
British thermal unit
Cubic feet
Cubic feet per minute
Cubic feet per second
Gigajoule (billion Joules)
Joule
Kilo Pascal
Kilowatt
Kilowatt hour
Kilowatt (electric)
Kilowatt (thermal)
Cubic meters
Cubic meters per day
Cubic meters per minute
Cubic meters per second
Thousand cubic feet per day
Megajoule (million .Joules) per standard cubic meter
Megawatt
Megawatt hour
Million (SI)
Million (English)
Million cubic meters
Million British thermal units
Million cubic feet per day
Metric tonne
Pounds per square inch, gauge
Catalytic Flow-Reversal Reactor
U.S. Environmental Protection Agency
Internal Combustion
Internal Rate of Return
Thermal Flow-Reversal Reactor
Volatile organic compounds
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Adiabatic
Air intake
Auto-combustion
Autothermic
Endothermic
Evase
Exothermic
Inby
Mine-mouth power plant
Outby
Oxidation
Parasitic loss
Prime mover
Regenerative heat
exchange
Voidage
GLOSSARY
Pertaining to constant heat value; with no external heat exchange.
Combustion air inlet (e.g., of an engine).
Combustion that can sustain itself without additional fuel; an
exothermic reaction.
Pertaining to a combustion process that can sustain itself; auto-
combustion.
A reaction that requires a net energy input (e.g., in addition to the
fuel value of the methane contained in the ventilation air); opposite
of exothermic
Cone shaped discharge plenum.
A reaction that supplies excess energy (e.g., requires no
additional fuel value other than methane contained in the
ventilation air); opposite of endothermic.
Away from the mine entrance (see outby).
A power plant co-located with a coal mine.
Toward the mine entrance (see inby).
The combination of a substance with oxygen (e.g., combustion).
That part of a prime mover's output that is consumed by ancillary
plant components.
A machine or mechanism that turns energy into work.
A process where heat is received, temporarily stored, and
released.
A measure of bed porosity; percent of volume not occupied by a
solid material.
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EXECUTIVE SUMMARY
Gassy underground coal mines in the U.S. and around the world release ventilation air
containing coal mine methane (CMM) at concentrations generally below 1.0 percent methane.
With few exceptions the mines operators allow the release of the methane to the atmosphere
without attempting to capture and use it. CMM emissions account for approximately 10 percent
of anthropogenic methane emissions worldwide, and methane emissions from mine ventilation
air comprise the largest portion of all CMM liberated worldwide.
When compared with drained CMM (e.g., in-seam and gob gas), ventilation air CMM is the most
difficult to use as an energy source because air volumes are large and require costly handling
equipment, and the methane resource is dilute and variable.
This report examines current and evolving methods for destroying and/or potentially using
ventilation air methane. It presents the results of a technical evaluation of these technologies by
the University of Utah (U of U). The report addresses energy conversion options to generate
project revenues, and it contains an economic analysis of actual and hypothetical project
configurations.
Technology Options
A project may use ventilation air methane as an ancillary fuel source to supplement the primary
fuel. For example, a power plant or other combustion unit may use ventilation air (instead of
ambient air) as combustion air. Ancillary projects usually would consume only a fraction of the
available ventilation air. The report discusses the Appin project in Australia which uses
ventilation air as combustion air in 54 internal combustion engines, each producing 1,000
kilowatts. This project is cost-effective, and one can expect to see more examples of ancillary
ventilation air uses at other gassy mine settings.
A project may soon be able to use ventilation air as a principal fuel source (i.e., as the primary
fuel that does not rely on a separate source of combustion) by using a flow-reversal reactor
such as those described in this report. This application would consume up to 100 percent of the
methane discharging from a single exhaust shaft. Two ventilation air methane processes
identified in the report are:
• MEGTEC's VOCSIDIZER, a thermal flow-reversal reactor (TFRR), is in use at over 600
locations throughout the world primarily for destroying organic contaminants. Only one
facility has operated exclusively on ventilation air, but about 200 other units use dilute
natural gas as a support fuel to supplement concentrations of target compounds (e.g.,
industrial volatile organic compounds).
• The catalytic flow-reversal reactor (CFRR), developed expressly for mine ventilation air
by Canadian Mineral and Energy Technologies (CANMET), is operating at bench scale
(500 mm diameter and 30 kW(t)) and will go into an industrial scale demonstration in
2000.
ES-1
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Technical Assessment of Flow-Reversal Reactors
Analysts at the U of U performed a technical assessment of TFRR and CFRR reactors using
numerical modeling, and they were able to draw significant conclusions:
• Both technologies are technically able to oxidize dilute methane in ventilation air.
• Both technologies will produce useable energy from a heat exchanger operating at a
useful temperature range.
• Based on laboratory and field experience, both the CFRR and the TFRR can sustain
operation with ventilation air containing methane concentrations as low as 0.1 percent.
Computer simulations performed for this report indicated that the CFRR and the TFRR
remained stable at methane concentrations just above 0.1 and 0.35 percent,
respectively. However, MEGTEC has observed that many of its TFRR units maintain
bed stability at methane concentrations at about 0.15 percent, and MEGTEC supplied
data that showed a unit exhibiting stable operation with a methane concentration as low
as 0.08 percent. This result is consistent with MEGTEC's simulation modeling but
contrary to the modeling performed for the U.S. Environmental Protection Agency (U.S.
EPA) study. U.S. EPA acknowledges that computer simulations are no substitute for
actual field observations.
• The lower limit of autothemnal performance is an important parameter because it
indicates the extent to which energy in ventilation air methane is recoverable or whether
supplemental energy is required to sustain reactor operation.
These independent observations, coupled with the fact that flow-reversal reactors have
operated successfully, give confidence that regenerative flow-reversal technology with or
without a catalyst will achieve success during commercial-scale field trials combusting actual
mine ventilation air methane.
Illustrative Economic Analyses
The report includes preliminary economic analyses of project scenarios using a flow-reversal
reactor coupled to: (1) a gas turbine cogeneration facility or (2) a waste heat boiler. Both
hypothetical projects appeared to be profitable when operating in appropriate energy markets,
especially while taking advantage of modest carbon credits for the greenhouse gas emissions
that the projects would mitigate. Economic assessments of ventilation air ancillary use projects
also concluded that such projects can be economically viable with various types of power plants
and primary fuels.
Because these economic studies were based on a series of assumptions and not actual field
data, it is too early to rely on them with total confidence. They are a source of hope, however,
that there are opportunities for economically eliminating methane emissions from ventilation air
shafts.
ES-2
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1.0 INTRODUCTION AND BACKGROUND
This U.S. Environmental Protection Agency (U.S. EPA) report is a technical and economic
assessment of existing and emerging processes for removing trace amounts of methane
contained in ventilation air streams at gassy underground coal mines by converting that
methane into useable energy.
Coalbed methane (CBM) is formed during the coalification process and resides within the coal
seam and adjacent rock strata. Coal mining activity releases methane that has not been
previously removed by drainage systems. The released methane then passes into mine
workings and on to the atmosphere. Gassy underground mines release significant quantities of
such methane, which is referred to as coal mine methane (CMM). When allowed to accumulate
in mine workings, CMM presents a substantial danger of fire and explosion. Operators of gassy
mines must remove methane to ensure miner safety and maintain continuous production.
Dilution by ventilation is the method most mine operators use to degasify air in the mine.
Ventilation systems consist of inlet and exhaust shafts and powerful fans that move large
volumes of air through the mine workings to maintain a safe working environment. Exhausted
ventilation air contains very dilute levels of methane; typical concentrations range between 0.2
to 0.8 percent methane, well below explosive limits. To date (with few exceptions) ventilation
systems release the air-methane mixture to the atmosphere without attempting to capture and
use it. Operators may supplement ventilation with another form of degasification (i.e., methane
drainage technology) which forcibly extracts methane from coal strata in advance of mining or
from gob areas after mining.
Some operators capture and use drained CMM employing a variety of proven methods, but
substantial quantities of drained CMM are also released to the atmosphere along with the
ventilation air. Methane emissions from ventilation air comprise the largest portion of all CMM
liberation worldwide, and they are the most difficult to use as an energy source. This report
examines the current and future possibilities for destroying and potentially using ventilation air
methane.
1.1 Global Importance of Ventilation Air Emissions
Methane is a potent greenhouse gas, approximately 21 times more effective than carbon
dioxide in terms of causing global warming over a 100-year time frame. CMM emissions
account for approximately 10 percent of anthropogenic methane emissions worldwide, and they
are the fourth largest source of methane release in the United States. While there are no
accurate data available measuring the relative quantity of CMM in ventilation air versus CMM in
drainage systems worldwide, ventilation air is the much larger and more important producer.
U.S. EPA estimates that ventilation systems emitted about 63 percent of all domestic CMM
liberated in 1997.1 Most other countries drain less and thus emit an even higher percentage of
CMM. For example, in China ventilation systems release as much as 90 percent of total CMM
liberated.2
1 U.S. EPA Report, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990—7996, EPA 236-R-
99-003, April 1999.
2 U.S. EPA Report, Reducing Methane Emissions from Coal Mines in China: The Potential for Coalbed
Methane Development, EPA 430-R-96-005, July 1996.
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Ventilation systems handle substantial air volumes. Consider this illustrative
example: a single ventilation shaft that emits 2 mmcfd (56,650 m3/d) methane
at a concentration of 0.5 percent. The total flow of the air-methane mixture
would be:
• 400 mmcfd (11.33Mm3/d)
• 16.67 mmcf/h (472 thousand m3/h)
• 278,000 cfm (7,875 m3/m)
• 4,630 cfs (131 m3/s)
If the diameter of the ventilation fan outlet is 20 feet (6.1 meters), the air would
move at a speed of 14.75 feet per second (4.5 meters per second).
As more mine operators install drainage systems or expand and improve existing systems, this
vented-to-drained ratio will decrease, but the absolute volumes of vented methane will continue
to be substantial. Therefore, an effective way to reduce CMM emissions would be to find
methods to capture and use (e.g. generate electricity from) methane that exits the ventilation
shaft.
1.2 Range of Emissions from U.S. Mine Ventilation Sources
This report identifies and assesses technologies that can be expected to handle the entire
ventilation stream from a single shaft. A typical shaft at a gassy mine in the U.S. will move
between 212,000 and 530,000 cubic feet per minute (cfm) or approximately 100 to 250 cubic
meters of air per second (m3/s). Ventilation exhaust air streams from gassy coal mines typically
contain methane at concentrations ranging from 0.3 to 0.7 percent. This report gives
information on a unit capacity of 212,000 cfm (100 m3/s) which would be a practical modular
size that mines could use singly or in multiples. A 212,000 cfm (100 m3/s) ventilation flow
containing 0.5 percent methane will emit 1.525 mmcfd or about 43,200 m3of methane per day.
1.3 Barriers to Current Recovery and Use
Ventilation airflows are very large, and the contained methane is so dilute that conventional
combustion processes cannot oxidize it without supplemental fuel. Ventilation air's
characteristics make it .difficult to handle and process it into useable forms of energy, and thus
constitute technical barriers to its recovery and use.
1.3.1 Technical Barrier 1: Lame and Costly Air Handling Systems
Typical ventilation airflows are so great that a processing system will have to be large and
expensive (see text box). Because the methane processing system will have to handle such
large airflows without introducing resistance to the mine ventilation system, it will need to
include a fan to neutralize whatever added resistance the reactor causes, thereby increasing the
system's capital and operating cost.
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7.3.2 Technical Barrier 2: Low Methane Concentrations
A methane-in-air mixture is explosive in a concentration range between approximately 4.5 and
15 percent. Below 4.5 percent, methane will not ignite or sustain combustion on its own without
a constant ignition source, unless it can remain in an environment where temperatures exceed
1,832 °F (1,000 °C). Therefore, any conventional method proposed to use ventilation air as a
fuel, or even to destroy it, would require a net energy input in addition to the fuel value of the
methane contained in the ventilation air.
1.3.3 Technical Barrier 3: Variable Flows and Changing Locations
Even if the first two barriers could be overcome, mine operators will face the flow variations
typically exhibited by a ventilation system. As mine operations progress underground, the
working face tends to move away from the original ventilation shaft. A processing system built
to accept a given flow will experience short-term periodic fluctuations and a probable decline
over time as other, more distant exhaust shafts take over larger shares of CMM liberated during
mining operations.
1.3.4 Institutional Barriers
When integrating systems that recover a fraction or all of the exhaust air with existing mine
ventilation systems, designers will need to consider possible impacts on the ventilation system's
effectiveness and take steps to maintain the mine's safety standards. To the extent that the
recovery project demonstrably meets the requirements of mining regulations, mine management
will be more likely to offer its cooperation in the venture.
1.3.5 Commercial Barrier
The major commercial barrier to ventilation air processing is that, under most situations, it
cannot survive in a business-oriented marketplace without externally applied incentives. Any
economically viable business will first exploit the resource that brings the most return, and
marginal resources will only receive attention after the more accessible resources have been
taken. The most marketable CMM commodity typically is pipeline-quality methane from
undisturbed coal seams. The next fuel to be exploited is gob gas, a mixture of methane and air
from gob drainage systems. Gob gas performs well as a substitute fuel in certain applications
such as boilers, internal combustion engines, or gas turbines, and it can be upgraded for
injection into natural gas pipelines. Ventilation air, the lowest quality gas byproduct of coal
mining, has a negative value in the marketplace (except for its use as combustion air, explained
below) because only one proven technology that uses its energy, ancillary use as combustion
air, is field-proven at this writing. Developers will not fully exploit it until it can demonstrate a
positive cash flow and an attractive internal rate of return.
1.4 Report Content
Section 2 of this report identifies and describes applicable ventilation air technologies, and
Section 3 presents excerpts and a summary of the technical evaluation of these technologies by
the University of Utah, Chemical Engineering and Fuels Department (U of U). (See Appendix A
for a description of the U of U's numerical analysis.) Section 4 addresses energy conversion
options to generate project revenues. Section 5 contains a comparative analysis of actual and
hypothetical project configurations, which illustrate projects that developers might find attractive
in various settings. This is followed by conclusions in Section 6. Appendix A contains U of U's
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technical evaluation; Appendix B presents the list of individuals who supplied information for this
report; Appendix C samples some commercial gas turbines that could be applied to a vent air
project; Appendix D presents a spread sheet model for allocating gob gas between the thermal
reactor and a gas turbine; Appendix E shows cash flow models for several ventilation air
methane use projects; and Appendix F summarizes recent CO2 trading activities.
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2.0 IDENTIFICATION OF APPLICABLE TECHNOLOGIES
This section examines some of the technologies that are available to mitigate ventilation air
emissions and use the contained energy beneficially.
2.1 Demonstrated and Emerging Technologies
The technologies divide into two basic categories:
• Ancillary Uses The focus of projects in this category is on a primary fuel that is not
ventilation air methane; thus, employment of ventilation air is ancillary and restricted to
amounts that are convenient for the project. For example, a power plant may use
ventilation air (instead of ambient air) as combustion air in internal combustion (1C)
engines, gas turbines, or other combustion units such as furnaces (collectively referred
to as prime movers) that use CMM as primary fuel. Projects of this type normally use
only a fraction of the ventilation air, but this report constructs a reasonable scenario
wherein a large nearby power plant could consume the entire flow from one exhaust
shaft.
• Principal Uses - Technologies in this category would use ventilation air methane as the
primary fuel, without relying on a separate source of combustion, and would attempt to
consume up to 100 percent of the methane emitting from a single exhaust shaft. As
discussed below, these systems may also employ more concentrated fuels such as gob
gas to enhance the utility or profitability of a given project.
2.2 Overview of Ancillary Use Technologies
All ancillary uses of ventilation air identified by U.S. EPA relate to its substitution for ambient air
in the supply of combustion air in various prime movers. Oxygen in the combustion air
combines with the primary fuel and the resulting combustion provides useful energy. The minor
amounts of methane in ventilation air provide supplemental fuel for the combustion process
along with necessary amounts of oxygen. The concept is simple, and it could find application at
many gassy mines.
The technique requires a modest air handling and transport system that serves to bring
ventilation air from the nearby ventilation shaft exit to the prime mover's air intake. The
maximum distance between the shaft and the prime mover must be determined with a case-
specific calculation that takes into account the physical site details and the economic benefit of
the supplemental fuel represented by the methane in the ventilation air. In some cases the
installation may require a booster fan to overcome pressure drops occurring in the transport
ducting.
2.3 Ancillary Use Process Descriptions
Three distinct types of prime movers that would be candidates for such an innovation are
combustion turbines, 1C engines, and large boilers or furnaces.
2.3.1 Combustion Turbines
Combustion turbines, or gas turbines, draw in combustion air through a compressor, which is
usually mounted on the same shaft as the turbine itself. After compression, the air passes
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through the combustor where the primary fuel and air ignite. If the combustion air were to
contain useable fuel, the operator could cut back on the quantity of costly primary fuel used.
U.S. EPA gathered information on this concept from four sources: a small development
company, two combustion turbine manufacturers, and a U.S. Department of Energy (U.S. DOE)
report.
Northwest Fuel Development.
Northwest Fuel Development of Lake Oswego, Oregon proved this concept experimentally in
the early 1990s. The company synthesized a ventilation air flow with natural gas and ambient
air and injected it into the combustion air intake of a small (225 kW) Solar Spartan gas turbine.
The turbine's fuel flow governor automatically reduced primary fuel flow to compensate for the
methane contained in the combustion air.3
Solar Turbines.
Solar Turbines, a division of Caterpillar Inc., has investigated this strategy for use with 3 to 8
MW turbines that would be located near mine ventilation shafts as the source of combustion air.
Although the company has no long-term field experience with the technique, Solar engineers
encourage its use in field applications, albeit within very strict methane concentration limits that
they impose to guarantee the safe operation of the equipment. Solar participated in the U.S.
DOE study described in the next section. Intake air in modern turbines functions both as
combustion air and cooling air. If a customer were to use mine ventilation air with a Solar
product, the company would insist that the mixture's methane content remain below one half of
one percent to maintain the unit's cooling system. A richer mixture might cause several
dangerous conditions (listed in the next section) in the interior of the rotor, which is the cooling-
air path that keeps the turbine blades from overheating. Allowing even small amounts of
methane in a turbine's intake air system is a complex issue, and Solar cautions that the
company must review and approve all applications involving ventilation air substitution. A Solar
engineer4 explained that each turbine model operating with any given combination of operating
parameters will result in a different percentage of intake air that actually goes through the
combustor (thus consuming the methane). Operating variables that affect this percentage
include pressure, temperature, low-NOx or standard model turbine, and excess air ratio. He
estimated that the ratio of methane destroyed (and converted to energy) to the total quantity
taken in might be as low as 20 percent and as high as 60 percent. For preliminary planning
purposes, one could expect that the fuel contribution supplied by a ventilation air stream
containing 0.5 percent methane might amount to about 10 percent of the turbine's fuel needs.
U.S. DOE Report.
U.S. DOE published a report entitled "Utilization of Coal Mine Ventilation Exhaust as
Combustion Air in Gas-Fired Turbines for Electric and/or Mechanical Power Generation" in
1995.5 The Phase 1 report contains ah analysis of the opportunities and limitations of
introducing ventilation air methane into the compressor of a Solar gas turbine, Centaur 40
model. The study team included a Solar research engineer, representatives from the coal
3 Personal communication with Mr. Peet Soot of Northwest Fuel Development, May 1999.
4 Personal communications with Mr. Mohan Sood of Solar Turbines. March 1998.
5 U.S. DOE Topical Report, Utilization of Coal Mine Ventilation Exhaust as Combustion Air in Gas-Fired
Turbines for Electric and/or Mechanical Power Generation, Contract No. DAC21-95MC32183,
December 1995.
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mining division of Jim Walter Resources, Inc., research scientists from the University of
Alabama, and other experts. Following are some of the report's major findings:
• The study team limited itself to a methane concentration of one half of one percent in the
ventilation air because larger concentrations would diminish the cooling performance of
the ventilation air by creating autoignition inside the rotor. Autoignition occurs when
water in the saturated ventilation air reacts with methane in the presence of nickel alloys,
forming combustible amounts of hydrogen and carbon monoxide (CO). This mixture
autoignites, probably in less than 1 millisecond, and causes an increase in turbine
internal and exit temperatures. Further research is needed to determine how severely
this phenomenon will affect turbine operation.
• The CO is unlikely to ignite in the rotor if inlet methane concentrations remain below one
half of one percent. Therefore, the turbine will emit increased amounts of CO plus
unburned hydrocarbons. Such increased emissions may require one of the following
additions to the facility design:
Cogeneration. A supplementary-fired heat recovery steam generator (HRSG)
producing steam as a byproduct of the plant.
Combined cycle. A supplementary-fired HRSG coupled to a steam turbine-
generator to produce additional electric power.
Post-combustion control. A catalytic oxidation system.
• If there is a possibility that ventilation air might contain more than one-half of one percent
methane, the facility will need an additional inlet for ambient air with controls to keep the
mixture at the desired concentration.
• A fraction of the ventilation air is used to pressurize the oil return system by forcing the
oil leaving the engine bearings back to the oil sump. Methane dissolves in most oils and
has a deleterious effect on lubricity. Thus, special gas stripper systems would be used
to remove the dissolved methane. The exhausted methane may form an explosive
mixture, requiring flame traps to ensure against ignition.
• A commercial wet scrubber should be used ahead of the gas turbine to eliminate the
coal fines usually found in the saturated ventilation air.
• The fraction of fuel provided by ventilation air methane is a function of the purity of
methane in the primary fuel. In the Centaur 40, when gob gas with 80 percent methane
is the primary fuel the ventilation air supplies about 12 percent of the fuel mix. With 100
percent methane the fraction moves down to about 10 percent.
• The team studied how they could raise the ventilation air methane to the maximum
practical fraction to conserve the cost of the primary fuel. They achieved a (calculated)
55 percent contribution from ventilation air methane by decreasing the gob gas flow.
This had the effect of lowering the turbine rotor inlet temperature (TRIT) to 1450 °F from
1660 °F. The lower temperature protects the rotor from effects described above, but it
derates the turbine from 3.415 MW to 2.5 MW. This approach was not economically
feasible because the small dollar value saved in gob gas cost was less than the value
that was lost as a result of decreased production. The team calculated the effect of an
intercooled recuperative (ICR) cycle which raised the calculated ventilation air methane
contribution to 62 percent. This was a costly option because an ICR requires a higher
-------
capital investment while earning marginal savings in fuel cost. The team even
speculated on a specially-designed gas turbine which could operate solely on methane
concentrations in the range of 1.4 to 2 percent. One of the several features to be
employed by such a design would be an externally plumbed, fresh-air cooling system.
The team has proposed a Phase 2 program which will design, construct, and operate test
facilities based on the calculations and conclusions from Phase 1.
GE Stewart Stevenson.
U.S. EPA made similar inquiries to GE Stewart Stevenson, a manufacturer of much larger
combustion turbines6 used for commercial power systems. That company maintains strict limits
on any contaminants in the combustion air stream. Engineers from GE Stewart Stevenson said
that they might review and possibly relax those limits to take advantage of the fuel values in
mine ventilation air only if a client paid for the research necessary to assure system integrity.
2.3.2 Internal Combustion Engines
1C engines, such as compression-fired diesel engines and compression ignition engines
modified to be spark-fired engines, commonly use medium-quality gas to generate electricity.
1C engines are good candidates for beneficially using part of a ventilation air stream by
substituting it for fresh ambient air in the combustion air intake. BMP Collieries Division has
proved this concept by using ventilation air as combustion air in 54 one-megawatt Caterpillar
3516 spark-fired units at the Appin Colliery in Australia. Two sources of methane, gas from in-
seam bore holes in advance of mining and gas from gob wells, supply the primary fuel for the
project.
Demonstrating a Partial Use of Ventilation Air Methane
At the Appin Colliery, BMP in Australia successfully
proved that ventilation air may be substituted for
combustion air in internal combustion engines:
• 54 one-MW CAT3516 engines.
• Primary fuel is drained coal mine methane.
• Ventilation air is 0.3 to 0.7 percent methane and contributes
between 4 and 10 percent of engine fuel.
• Consumes on the order of 20 percent of ventilation
emissions.
The project's unique feature is that combustion air for each engine located at Appin is supplied
by mine ventilation air, which until recently averaged about 0.7 percent methane. Due to
improved CMM drainage and increased flow through the fans, the methane concentration will
fall to 0.3 percent or below. There are no fans in the ductwork taking ventilation air to the
engines because the turbochargers on each engine have sufficient suction power to overcome,
6 Personal communication with senior advanced turbine engineer, GE Stewart Stevenson, a General
Electric gas turbine packager. May 1999.
8
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without noticeable loss of engine performance, the 0.58 psig (4 kPa) pressure loss through the
ducts and air scrubbing and filtering system.
The inlet to the duct is a free collection hood mounted about 5 feet (1.5m) above the discharge
of the mine ventilation fan. The reasons for this configuration are:
• To eliminate back-pressure on the ventilation fan, even when the engines are not taking
any air. This was confirmed by testing.
• To keep the duct (and by inference the 1C engine power station) separate from the mine
ventilation system so they are not under the jurisdiction of mine inspectors.
The fuel value contributed by this air stream peaked at about 10 percent of each engine's fuel
needs during the early years, but this contribution has fallen to near 3 percent recently. Since
the project must rely on natural gas to supplement its primary fuel during periods of low CMM
availability, the methane from ventilation air represents a significant cost savings on purchased
fuel.7' 8'9 To regulate the fuel needed by the engines, the project uses an electronic control
system that balances the volume of drained CMM, ventilation air methane, and natural gas.
Further details on this project's commercial and economic aspects are presented in Section 5 of
this report. Figure 1 is a schematic diagram of the Appin project.
.Primary fuels:
/ • CMM (in-seam and gob gas)
Ventilation air
0.7% CH,
/
—
i
/ • Natural gas (when necessary)
/
' S~\
___^-^
• Exhaust fan
- Ventilation shaft
1C Engine-Generator
Figure 1. Schematic Flow Diagram of the Appin Project
7 State of the Art Power System Converts Methane to Energy at Australian Coal Mines, paper given by
L.D. Lloyd, Caterpillar, Inc., Lafayette, IN, at the U.S. EPA Conference in Pittsburgh, PA "Marketing
Your Coal Mine Methane Resource", April 9,1998.
8 Personal communications from Geoff Bray, former Project Engineer with BHP Engineering, December
1998 and October 1999.
9 The Appin and Tower Collieries Methane Energy Project, a BHP Engineering Pty. Ltd. report provided
by Geoff Bray, Project Engineer, on September 26,1998.
-------
2.3.3 Other Ancillary Uses
If ventilation air could be delivered to a large fuel consumer such as a coal-fired power boiler or
a brick kiln located near the ventilation air source (e.g., within approximately 500 yards or
450 m), it could readily replace ambient air for all or part of the combustion air requirements.
For example, a ventilation shaft emitting 2 mmcfd (56,640 m3/d) of methane could supply
enough combustion air for a mine-mouth, coal-fired power plant rated at approximately 125 MW.
This technique is technically feasible, especially if the plant already exists or will soon be built
near a mine ventilation shaft. Powercoal, an energy company in Australia, is considering a
direct interconnection between mine ventilation fans and forced draft fans at an existing
adjacent coal-fired power plant. For a new plant, however, a power developer must assess the
likelihood of an adequate supply of ancillary fuel over the economic life of the plant. Section 5
presents an economic analysis of an illustrative case featuring a 125 MW coal plant.
2.3.4 Summary of Ancillary Uses
This investigation has revealed that, within certain limits, it is technically feasible to use
ventilation air as combustion air in a variety of energy facilities such as combustion turbines, 1C
engines, and large furnaces and boilers. In fact the concept is quite simple and its application is
straightforward.
• Small-scale experiments have shown that combustion air substitution in gas turbines is
technically feasible. Technical investigations are needed (1) to ascertain the limits of
methane intake with a small gas turbine application, and (2) to demonstrate the concept
with large gas turbines.
• Combustion air substitution is technically feasible, state-of-the-art, and commercially
demonstrated with 1C engines.
These ancillary uses exhibit a common pattern, including:
• All processes require a separate energy source, the primary fuel, to generate the
temperatures needed to combust dilute methane in the ventilation air.
• The air handling and transport system needed to bring ventilation air to the prime
mover's air intake is not costly if the facility is reasonably close to the exhaust shaft. For
example, Caterpillar reports that the system at the Appin Colliery represented a small
percentage of the capital cost of the entire plant. Unless the transport distance is long,
requiring booster fans with significant power demands, there will be little operational cost
associated with ventilation air use.
• The technique benefits users of costly primary fuels by reducing fuel purchases on the
order of 8 to 10 percent.
• The technique allows users of gob gas, an inexpensive primary fuel, to produce more
power than would otherwise be possible.
• Applications using small gas turbines and 1C engines reduce methane emissions by as
much as 20 percent of a mine ventilation shaft's output, while large coal plants may
accept up to 100 percent.
10
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2.4 Principal Use Technologies
The search for principal use technologies, defined as those technologies that can combust
dilute methane in ventilation air as a primary fuel without reliance on another source of
combustion, yielded two processes:
• A thermal flow-reversal reactor (TFRR) process, offered by MEGTEC Systems, a
subsidiary of Sequa Corporation, a U.S. company.
• A catalytic oxidation process called the Catalytic Flow-Reversal Reactor (CFRR),
developed by a consortium of Canadian interests including CANMET.
A description of each system and its development status follows.
2.4.1 Thermal Flow-Reversal Reactor
History.
MEGTEC Systems10 offers the VOCSIDIZER, a TFRR that operates above the autoignition
temperature of methane (i.e., above 1832° F (1000° C)). It is a modification of a commercially
proven process for the thermal oxidation of volatile organic compounds (VOCs). MEGTEC has
over 600 of these TFRR installations in a variety of applications for VOCs and odor emission
reduction. For example, a large (116,500 cfm or 55 m3/s) TFRR unit for VOCs oxidation
operates at the Volvo plant in Gothenburg, Sweden. Such a unit would have about half the
capacity required to process air from a small to medium-sized mine ventilation shaft. This unit
operates on a mixture of injected methane (in the form of natural gas) and paint solvents during
periods when solvent concentrations fall below the limit required for self-sustained operation.
Many other MEGTEC installations also are capable of injecting methane to assure stability.
In addition, MEGTEC reported that a 6,350 cfm (3 m3/s) demonstration TFRR unit operated at a
British Coal mine site for a period of six months. The company learned that the unit effectively
destroyed methane in a partial flow withdrawn from the mine ventilation exhaust. Detailed
information from those trials is not available at this time.
Description.
Figure 2 shows a schematic of the TFRR reactor. This is a simple apparatus that consists of a
large bed of silica gravel or ceramic heat exchange medium with a set of electric heating
elements in the center. Airflow equipment such as plenums, ducts, valves, and insulation
elements are fitted around and within the bed. Controls and ancillary equipment are mounted
nearby.
10 MEGTEC is a De Pere, Wisconsin-based subsidiary of Sequa Corporation. The VOCSIDIZER was
developed by ADTEC of Sweden, which now is a part of MEGTEC.
11
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....... , ^. :
t, ^
*
Valve 2
Air&
CH4
Valve 1
Heat Exchange Medium
• Heat
•
— Exchanger
Heat Exchange Medium
t
Valve 1
Air, CO2,
H2O&
Heat*
Valve 2
Valve #1 open =
Valve #2 open ~
*Heat recovery piping not
shown
Figure 2. Schematic of Thermal Flow-Reversal Reactor (TFRR)
12
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Principles of Operation.
The process employs the principle of regenerative heat exchange between a gas (ventilation
air) and a solid (bed of heat exchange medium selected to store and transfer heat efficiently) in
the reaction zone. In Figure 4 the ventilation air enters from the left and leaves at the right
during the entire operation. One cycle of the process is comprised of two flow reversals, so
each flow reversal is a half-cycle. Referring to Figure 4, assume that during the first half-cycle
both valves number 1 are open while valves number 2 are closed. Thus, the flow through the
reactor takes place from bottom to top. After a time interval determined by the reactor's
temperature profile, the reactor reverses flow direction by closing valves 1 and opening
valves 2. Flow then takes place from top to bottom.
To start the operation, electric heating elements preheat the middle of the bed to the
temperature required to initiate combustion (i.e., >1832° F (1000° C)). During the first half of the
first cycle, ventilation air at ambient temperature enters and flows through the reactor in one
direction. Methane oxidation takes place near the center of the bed when the mixture exceeds
the combustion temperature of methane. If that temperature can be maintained in the bed,
practically 100 percent conversion of methane (to carbon dioxide and water) can be achieved.
If the gas is not heated to the autoignition temperature of methane, the reaction will not start.
Because such a condition provides no heat source, the preheated solids are slowly cooled by
the incoming gas. The gas temperature rises at first and then drops slowly until both solid and
gas are at the feed gas temperature. The process thus ends at the first half-cycle. This
situation is called a non-starter.
Even if the reaction does start, the final conversion must be complete enough to cause a
sufficient temperature rise that will heat the gas in the next cycle to the autoignition temperature.
Otherwise, the behavior exhibited by the reactor in the first half-cycle of a non-starter is again
observed, but over a number of cycles. This situation is called a blow-out.
After the initial cycles, hot products of combustion and unreacted air continue through the bed,
losing heat to the far side of the bed in the process. When the far side of the bed is sufficiently
hot and the near side has cooled, the reactor automatically reverses the direction of ventilation
airflow. New ventilation air enters the far side of the bed and becomes hotter by taking heat
from the bed. Close to the reactor's center the methane reaches autoignition temperature,
oxidizes, and produces heat to be transferred to the near side of the bed before exiting.
Temperature at the core reaches 1832° F (1000° C) plus the adiabatic temperature rise, and
then decreases as the heat exchanger removes heat from the unit. The details of flow reversal
are discussed in the following paragraphs.
In an ideal situation the temperature profile in the bed would be as shown in Figure 3. When the
ventilation air flows from the bottom of the chamber to the top it picks up heat from contact with
the hot solid media, and its temperature increases. The gas temperature lags the solid
temperature by a few degrees both while gaining and losing heat. MEGTEC indicates that this
gas-to-solid lag has been between about 20° C to 50° C in existing units. As the flow continues
in the initial half-cycle, the temperature hot zone, with respect to both the solid and the gas,
tends to migrate upward (for the bottom-to-top illustrative flow configuration). The flow reversal
arrests this upward migration and prevents it from traveling too far from the center. The next
half-cycle flow (top-to-bottom) produces a new temperature profile, also shown in Figure 3. By
switching flow direction at precalculated and preset time periods, typically about 120 seconds,
the hot zone can be maintained in the center of the reactor. MEGTEC prefers to keep a short
13
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cycle time so that the location of the maximum bed temperature shifts only a short distance up
and down while the profile maintains its shape.
Bed Height
Gas temperature, if
the gas is flowing
downward
Gas temperature, if
gas is flowing
upward
Solid
temperature
Temperature
Figure 3. Illustrative Ideal Temperature Profiles in TFRR
Figure 3 shows that, even with very efficient heat transfer, the exit air temperature is at least a
few degrees higher than the incoming ventilation air. As a result, if no energy is generating
internally, the bed would eventually cool. MEGTEC claims that if the methane concentration in
the incoming air is consistently 0.15 percent or more, and if the unit has been optimized to meet
that parameter, the operation will be autothermic (i.e., it will support itself without additional
applied heat or fuel). This would mean that oxidizing this quantity of methane will produce
enough heat to compensate for an approximate 72°F (40°C) temperature rise in the exit gas
flow (relative to incoming gas temperature), which represents a heat loss from the process. It
also is a measure of the efficiency of the heat exchange between gas and solid. The company
claims that other heat losses from the reactor are negligible. To substantiate its statements, the
company provided data on a unit operating in the field. During typical weekends there are no
product emissions to be destroyed, so the operator sustains the reactor by injecting natural gas.
The submitted data showed that this unit can sustain operation by maintaining the core
temperature just above the autoignition temperature of methane with a methane concentration
of approximately 0.08 percent. One of the objectives of the technical assessments and
numerical modeling described in Section 3 and Appendix A is to duplicate independently the
phenomena that MEGTEC describes as field experience.
Heat Recovery.
If the methane concentration in ventilation air exceeds the level necessary for self-sustained
operation, the process can recover high-quality heat and still maintain a steady-state operation.
14
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Figure 4 shows the cyclic steady-state solid temperature profile of the bed in an ideal operation
with heat recovery.
Bed Height
Initial temperature profile
Final temperature profile
Temperature
Figure 4. Illustrative Ideal Heat Exchange Medium Bed Temperature Profiles in TFRR
If the reactor has sufficient methane to reach thermal equilibrium, its exhaust gas temperature
will be raised by a value equal to the adiabatic temperature increase in the reactor. The
temperature reached depends only on the inlet methane concentration.
Adiabatic temperature rise is defined as the temperature
differential between the reactants and products
assuming there is no external heat exchange and that all
of the heat of reaction goes toward increasing the
temperature of the products.
There are three different methods of excess heat removal, depending on the amount of excess
heat to be recovered and the specific application.
• Heat can be recovered from exhaust gases exiting the reactor. However, this heat will
not be of high quality because the exit gas temperature will be much lower than that of
the gas as it passes through the combustion zone. For example, the adiabatic
temperature increase for one-percent methane would be about 477° F (265 °C), 0.5
percent methane would be about 239° F (133 °C), and 0.1 percent methane would be
about 43° F (24° C).
15
-------
• The second method for recovering heat is by inserting heat transfer coils (containing air,
water, or other media) into the hot zones of the reactor and recovering a much higher-
quality heat (e.g., 700° C to 800° C). The technical review of energy recovery methods in
Sections 4 and 5 of this report concentrates on this more practical, high-temperature
heat exchange method. One example is the use of compressed air from a gas turbine's
compressor as the heat sink for the reactor. The heated, compressed air returns to the
turbine, expands through the turbine blades, and produces power. Another example is
the use of water as the heat transfer medium to produce steam.
• The third method is to use part of the gas at its highest temperature directly for heat
transfer and to let the remaining part pass through the system. This recovery technique
will be the most complicated of the three.
Commercial Status.
Although MEGTEC has been marketing its TFRR for use at gassy mines for several years, the
company has not installed a commercial-scale demonstration unit. {Note: The capacity of the
unit used for the British Coal trial was only 6,350 cfm (3m3/second).} However, they intend to
increase their marketing efforts to establish a demonstration plant at an operating mine.
2.4.2 Catalytic Flow-Reversal Reactor
History.
In 1995 researchers at Energy Diversification Research Laboratory/Natural Resources Canada
(EDRL/NRCan) in Varennes, Quebec (also known as Canadian Mineral and Energy
Technologies or CANMET) conceived of and developed the Catalytic Flow-Reversal Reactor
(CFRR) expressly for use on coal mine ventilation air methane. The research team was well
aware of thermal flow-reversal reactor technology and its use in other applications, but they
desired to improve the TFRR so that it could process mine ventilation air at lower temperatures.
As a result of this research, CANMET selected a catalyst that reduces the autoignition
temperature of methane by several hundred degrees Celsius. The CFRR technology
development has included demonstration of the concept over a range of simulated conditions at
small scale. CANMET and several Canadian private and government entities have formed a
consortium to finance, design, build, and operate an industrial-scale demonstration plant
(approximately 16,900 to 21,200 cfm (8 to 10 m3/s)) at a mine in Nova Scotia. CANMET is also
studying energy recovery options that are appropriate for the CFRR, especially the gas turbine
option.
Description. The CFRR has the same basic design and operation as the TFRR described
above. Figure 5, a schematic of the process, shows that the reactor has three sections. The
sections at the two ends of the bed are packed beds of inert materials. During "top-to-bottom"
flow, the top section provides heat to the incoming ventilation air and raises it to a temperature
at which combustion in the presence of a catalyst will commence in the center section. As hot
products of combustion pass into the bottom section, their heat transfers to the bed, raising its
temperature. The section housing the reactor and the heat exchanger lies between the two
inert beds and contains catalyst pellets. All three sections of the reactor are well-insulated so
that little heat is lost to the surroundings.
16
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Valve 2
Air&
CH4
Valve 1
t
Heat Exchange Medium
Catalyst
Heat
Exchanger
t
Catalyst
Heat Exchange Medium
t
Valve 1
Valve 2
Air, CO2,
H2O&
Heat*
Valve #1 open =
Valve #2 open =
*Heat recover}' piping not
shown
Figure 5. Schematic of Catalytic Flow-Reversal Reactor (CFRR)
17
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Principles of Operation.
CFRR's operating principal is identical to that of its thermal counterpart except that the reaction
is catalytic and therefore takes place at much lower temperatures. The advantages of this
process are discussed in the technology assessment below. They include a more stable
reaction and longer cycle times.
Heat Recovery.
Heat recovery options and operating principles for the CFRR are identical to those discussed
above for the TFRR. There are differences in the method of heat transfer and quality of heat
recovered from the two systems, however (see discussion in Section 4). CANMET has
experimental evidence of heat recovery between 50 and 90 percent of the input heat value of
the methane.
Commercial Status.
The Canadian consortium that will demonstrate the CFRR at industrial scale hopes to have the
unit operating at a mine site in Nova Scotia in 2000. Once success of this unit has been
demonstrated, the group will commence active marketing to the coal mining and energy
industries.
2.4.3 Summary of Principal Uses
Investigation for this report revealed two systems that may be suited for capturing, destroying,
and using the energy from dilute methane contained in mine ventilation air. Both the TFRR and
CFRR employ the flow-reversal principle to transfer methane's heat of combustion, first to a
solid medium, and then back to incoming air to raise its temperature to the ignition temperature
of methane. Both system vendors affirm that NOX emissions from their units are low. CO
emissions will probably be low as well because combustion takes place in a high excess air
environment, but the vendors did not comment on this. The two systems differ only with respect
to the use of a catalyst. The CFRR uses a catalyst to reduce methane's combustion
temperature.
The following factors give some encouragement to the future of mitigating ventilation air
methane emissions with flow-reversal reactors:
• There are over 600 TFRR units operating in the field, most of them serving to destroy
harmful organic emissions. According to MEGTEC, one unit has operated with mine
ventilation air as its primary fuel, and several other units use injected methane to sustain
operation.
• Some TFRR installations recover and use excess heat by employing heat exchangers
embedded in the reactor. MEGTEC states that these heat exchangers do not upset the
stability of the temperature profile. The company is unable to disclose further design
details because of confidentiality issues.
• The CFRR, designed and tested exclusively for use with coal mine ventilation air, has
fully demonstrated its ability to combust a wide range of input conditions in laboratory
trials. CANMET has collected comprehensive data showing that the unit operates with
methane concentrations as low as 0.1 percent and recovers high fractions of available
18
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heat. The laboratory has correlated its experimental data with results predicted by a
sophisticated computer modeling program.
• CANMET also tested the CFRR in an actual mine ventilation air environment at the
Phalen Mine in Nova Scotia. After exposing a unit with its catalyst to mine exhaust for
four months, CANMET found no deterioration of the catalyst beyond the normal decay
that they had observed in the laboratory. This trial proved that dust carried by the
ventilation air had no adverse effect on the unit, and it confirmed the previous findings on
expectations for catalyst life.
• MEGTEC has presented evidence that a TFRR unit operating in the field routinely
operates with methane concentrations as low as 0.08 percent.
• Both the TFRR and the CFRR will be able to withstand temporary interruptions in the
feed stream because of their considerable thermal capacity. CANMET operated the
CFRR on a 0.5 percent methane feed stream and allowed the core temperature to rise
well above autoignition temperature (in the presence of a catalyst). They then shut off
the feed stream and monitored the slowly declining core temperature until it reached the
autoignition limit 17 hours later. This phenomenon will bring practical benefits to field
applications during periods of equipment maintenance or mine ventilation changes.
• Both MEGTEC and CANMET are confident that they can build reactor modules in sizes
large enough to capture and process most or all of the airflow from a typical mine
ventilation shaft with a small number of modules.
Table 1 presents some of the significant differences and similarities between the two
technologies.
Table 1. Summary of Differences and Similarities Between the TFRR and
the CFRR
Feature
Principles of operation
Catalyst
Autoignition temperature
Experience
Cycle period length
NOX and CO emissions
TFRR
Same
No
1832°F(1000°C)
600+ units in field, some
operating on methane
Shorter
Low
CFRR
Same
Yes
662°Fto1472°F
(350°Cto800°C)
Bench scale trials with
simulated mine exhaust
Longer
Low
Sections 3, 4, and 5 of this report address three remaining issues related to the viability of flow-
reversal technology for destroying methane in mine ventilation air: confirming technical
feasibility of the reactors, integrating energy recovery technology, and assessing cost
effectiveness.
19
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2.5 Technical Considerations in Adapting Air Handling Systems to Mine Ventilation
Facilities
Mine ventilation systems for gassy coal mines are typically equipped with large above-ground
exhaust fan installations. The majority of mines use exhausting ventilation fans rather than
forcing fans. As previously mentioned, a system designer who integrates an existing ventilation
system with a processing facility that recovers all or a fraction of the exhaust air will need to
consider impacts on the mine's ventilation system and take steps to maintain the mine's safety
standards. The recovery project must meet the requirements of both mine management and
mining regulatory authorities.
2.5.1 Impacts on Mine Ventilation System
Whether designers recover the ventilation air from passive air ducts installed directly into the
fan's discharge evase (cone shaped discharge plenum) or through ducts connected on the
outby or inby sides of the mine's fan, engineers should ensure that the performance
characteristics of the integrated system, with respect to total pressure and airflow, are similar to
that of the mine's original design. Ducts installed in an evase increase system resistance, and
air splits located inby or outby the fan disturb flow paths and increase air turbulence. Therefore,
all recovery configurations will increase fan operating pressures unless the system introduces a
negative pressure from downstream, and that must be a requirement for every project.
Aerodynamically designed installations will minimize resistance and shock losses attributed to
ventilation air collection infrastructure.
2.5.2 Integration With Fans Operating Within Oxidizer Systems
Inby locations.
A ventilation methane oxidizer may be equipped with a fan operating at total mine pressure and
configured to recover ventilation air inby the main mine fan. Mining authorities will consider
such an active facility to be an integral part of the mine's ventilation system, and they will
subject such facilities to the same coal mine safety guidelines applicable to main mine fans.
Depending on the country of operation, these regulations may stipulate permissible in-line
electric motors, incombustible ducting, monitoring systems and alarms, independent power
supply, backup motor (non-electric) or fan, explosion force relief provisions, and incombustible
fan isolation doors.
Outbv locations.
To facilitate approval and application, the authors recommend that the methane recovery
facilities contemplated in this report recover ventilation air outby main mine fans. With this
configuration, mining authorities will likely only stipulate the permissibility requirements (e.g.,
permissible in-line electric motors, monitoring system with alarm, and incombustible ducting).
For all ventilation air recovery systems contemplated, designers will need to assure regulators
that the methane recovery system, and any secondary energy recovery circuit, such as a gas
turbine, will not produce explosive methane-and-air mixtures. The design should also ensure
that if a deflagration in the methane recovery or secondary energy recovery circuit were to
occur, sufficient safety measures are in place to isolate these facilities from the mine's
ventilation system. Designers should also make clear to the mine operators and the regulators
that the recovery system will incorporate its own air transport system for the oxidizer and will not
burden the existing ventilation system.
20
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3.0 TECHNICAL EVALUATIONS
The University of Utah (U of U) prepared a technical assessment of the TFRR and CFRR
chemical reactor processes using computer simulation techniques. The following discussion
summarizes their methodology and outlines their findings. Appendix A provides details on the
numerical simulation models developed to perform the technical assessments and presents the
quantitative results.
3.1 Numerical Modeling
3.1.1 Assessment Methodology
In this assessment, the U of U developed and used a numerical computer model. Numerical
reactor models are widely used tools that simulate chemical reactors and assess their technical
feasibility. To build the model, the analyst first describes the physical phenomena occurring in
the reactors and then writes mathematical descriptions of each. Generally, several simplifying
assumptions are necessary prior to expressing the physical system in its mathematical form so
that the mathematical equations are computationally amenable. The model solves those
equations, usually differential equations, using appropriate boundary conditions. Models are
useful for providing design guidelines and later for optimizing reactor performance. In the
current context, the models simply tested the feasibility and displayed operating characteristics
of the two processes.
The U of U created the model and modified it for each of the two reactors. The models did not
incorporate a heat recovery section since this component of the process depends heavily on
site-specific choices for the most appropriate heat recovery method. Some of the necessary
design parameters were not furnished by the system suppliers because such information is
case specific, not yet available, or proprietary. However, by working with the vendors and
making reasonable assumptions based on similar processes found in the literature, the analysts
at U of U were able to select a reasonable range of physical parameters to employ in the model.
These parameters include reactor configuration, types of materials, voidage (which is a
measure of bed porosity), pressure drops, velocities, and temperature profiles.
3.7.2 Thermal Flow-Reversal Reactor
The process modeling showed that the TFRR oxidizer is a feasible option for utilizing the
methane available in coal mine ventilation air. The TFRR operation is stable for a properly
chosen set of design parameters and operating conditions.
Initially, the reactor is hot in the middle with the temperature tapering off at either end. The
initiation temperature at the center is on the order of 1832 °F (1000 °C). The ventilation air
enters the reactor at room temperature. As the operation proceeds, the temperature of the
exhaust gases increases by the adiabatic temperature rise. If the exhaust reaches
unacceptably high levels, heat recovery may be essential. The U of U's observations on the
TFRR simulation are summarized below:
• Below 0.35 percent methane the simulation calculations indicated that blow-out would
occur. This result goes counter to MEGTEC statements (and the results of its own
computer simulations) that the unit will continue to function at concentrations of 0.08
methane. The company confirmed this claim by submitting data on a unit that operates
21
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in the field destroying organic odors during weekdays only. Because there are no
product emissions during weekends to sustain temperatures in the reactor the operator
injects methane into the airflow to prevent blow-out. The data show that the average
methane concentration during this period was about 0.08 percent while the reactor core
temperatures remained at just above 1000° C.11
• While operating in the expected range of ventilation air methane concentrations (e g
0.4 to 0.6 percent methane), the U of U's TFRR simulations were stable.
• The energy required to bring the reactor to methane combustion temperature is
substantial, but since start-up should be an infrequent occurrence, it is insignificant when
spread over a project's life-cycle.
The U of U concludes that the TFRR, operating on a steady supply of ventilation air methane at
concentrations typically encountered in the field, is a technically feasible process for oxidizing
methane. Uncertainty arises when the concentrations approach the level at which blow-outs
occurred during simulation trials. Mathematical models are inherently limited by the physical
phenomena that they represent. The model in this study incorporated all of the logical physical
phenomena in the transport and reaction of ventilation air in these reactors. Even with the
state-of-the-art mathematical representation, however, models only approximate physical
reality. While the model predicts blow-out below 0.35 percent methane, MEGTEC affirms that
its own model shows that the process continues to be autothermal even below 0.1 percent
methane. The researchers at U of U concede that under certain reactor configurations and with
different design parameters it may be possible to lower the methane concentration bound at
which the TFRR operates autothermally.
More persuasive in terms of assessing stability at low methane concentrations, however, are the
reports from the field. According to MEGTEC, over 200 operators of their TFRR units regularly
add natural gas to industrial airflows, just as in the case cited above. These airflows temporarily
contain low levels of combustible material and would otherwise blow out. MEGTEC reports that
these injections produce methane concentrations similar to those normally found in mine
ventilation air, so this practice increases the body of field experience MEGTEC can claim in
processing dilute methane flows. MEGTEC also suggests that a ventilation air project operator
could inject gob gas into a TFRR to enhance the methane concentration.
3.1.3 Catalytic Flow-Reversal Reactor
The U of U analysts ran a simulation of the catalytic flow-reversal reactor under conditions
identical to the TFRR trials and found it to be technically feasible as well. The simulated
process modeling clearly showed that during steady-state operation the CFRR remains stable
and autothermic at low methane concentrations. It blows out only when concentrations reach
just above 0.1 percent. CFRR cycle duration appears to be longer than TFRR cycles, but this
difference will not have a material effect on system performance.
The assessment did not take into account the potential for conditions that could adversely affect
catalyst performance (e.g., temperature cycling or catalyst poisoning from sources such as
dust). These concerns can be studied during field trials. If such problems occur they will result
11 The supporting data were contained in a report entitled Submission of Additional Information from
MEGTEC Systems-Applicability of the VOCSIDIZER, July 1999.
22
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in increased operation costs because of more frequent catalyst replacement and unscheduled
down time.
3.1.4 Pressure Drop
In addition to the numerical modeling, the U of U research team performed an analysis of
pressure drops created by the volume of ventilation air passing through the systems. The U of
U analysts calculated pressure drops for a range of flow rates, reactor diameters, and voidage
fractions. Since they used an "effective diameter", the results are valid for any internal
configuration. Calculated pressure drop results were not excessive. That finding, shown in
Table 2, indicates that manufacturers should be able to install reactors of a reasonable size and
still maintain required air velocities using affordable fan systems. For example, with a voidage
fraction of 0.5, a flow rate of 21,200 cfm (10 m3/s), and a diameter of 19.69 ft (6 m), the pressure
drop is less than 15.75 inches (400 mm) of water. The calculations also confirm pressure drop
data reported by CAN MET.
Table 2. Pressure Drops for CFRR and TFRR Processes Using Various
Flow Rates, Diameters, and Voidages
Flow Rate
Cfm/(m3/s)
2,120/1
2,120/1
2,120/1
2,120/1
21,200/10
21,200/10
21,200/10
21,200/10
Diameter"
ft/(m)
3.61/1.1
3.61/1.1
6.56/2.0
6.56/2.0
11.48/3.5
11.48/3.5
19.69/6.0
19.69/6.0
Velocity
ft/s/(m/s)
3.12/0.95
3.12/0.95
1.05/0.32
1.05/0.32
3.41/1.04
3.41/1.04
1.15/0.35
1.15/0.35
Voidage Fraction
0.5
0.7
0.5
0.7
0.5
0.7
0.5
0.7
Pressure drop
(in/mm water)
45.79/1163
8.90/226
13.86/352
2.68/68
45.20/1148
8.79/223
15.35/390
2.99/76
* Effective diameter. In practice, smaller multiple units may be used.
Source: University of Utah.
23
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3.2 Technical Assessment Summary
Numerical modeling and gas flow calculations demonstrate that both flow-reversal oxidation
processes are technically feasible. It is too soon to render definitive opinions on comparative
performance because neither the CFRR nor the TFRR has operated on mine ventilation air at
commercial scale, under actual field conditions, with full documentation. As discussed in
Section 5, while there is little apparent difference in terms of unit capital and operating costs,
there are a few factors that may tend to affect the selection of one process or the other.
3.2.1 Catalytic Flow-Reversal Reactor
• CANMET asserts that catalytic oxidation allows the use of smaller units because with
lower temperatures the wave front moves more slowly, thus traveling a shorter distance
between flow reversals. Both the lower temperatures and smaller size tend to favor a
lower capital cost. The catalytic process, however, must bear the added cost elements
of purchasing, maintaining, and replacing the catalyst.
• Because the CFRR has been developed specifically for the treatment of mine ventilation
air, it may perform more efficiently and cost-effectively than the TFRR. Field trials will
prove or disprove this supposition.
• While U of U computer simulations indicate the CFRR is able to operate at lower
concentrations, MEGTEC's field data confirm that the TFRR can match that
performance. This factor is important in estimating how much energy effectively can be
recovered from the reactor (see detailed discussion in Section 4).
3.2.2 Thermal Flow-Reversal Reactor
• With over 600 TFRR units operating in the field, MEGTEC would seem to have an
advantage in terms of "proof of concept" as compared with CFRR's laboratory trials and
modeling. Many of these units must operate intermittently on methane of similar
concentration levels as ventilation air methane during periods when normal feedstock is
in short supply.
• The TFRR has no operating costs associated with a catalyst.
24
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4.0 PRACTICAL METHODS FOR USING ENERGY RECOVERED FROM VENTILATION AIR
OXIDIZERS
While the emphasis of this report is on the ability of various technologies to combust methane in
ventilation air, it is important to explore the practical systems that will recover and use the
energy thus created, enabling developers to install and operate such systems profitably. This
section examines some of the technical issues of energy recovery and introduces some
methods that may be practical and cost-effective.
4.1 Heat Available for Recovery
When methane borne by the ventilation air combusts, it releases heat, but not all of that heat is
available for recovery. Some of the heat is required to sustain reactor temperatures, and if
methane concentrations are in the lowest sustainable range, most or all of the heat of
combustion goes for that purpose. Figure 6 depicts the relationship of recoverable energy as a
function of methane concentration. The higher the available concentrations are (i.e., the area
where the curve begins to level off) the greater will be the percent of heat that may be recovered
by the heat exchanger. Figure 6 covers a broad area having its origin at a range of points on
the X-axis between 0.1 and 0.3 percent methane, representing the minimum methane
concentration of ventilation air at which the reactor is autothermic. The two reactors reviewed in
Section 3 are autothermic at temperatures consistent with this range.
100
90
80
§ 70
o
60
d>
£ 50
CD 40
o
o
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Upon examination of the curve one can see that a small increase in methane content may result
in a dramatic increase in the amount of energy available for recovery and use, especially in the
steeper parts of the curve. Injection of methane at this point not only creates more heat but it
causes a larger fraction of that heat to be recovered. Therefore, developers may wish to
consider the possible economic advantages of injecting gob gas into the ventilation air stream to
exploit this phenomenon.
MEGTEC has reviewed the practicalities of injecting methane in the form of gob gas into the
ventilation air as a support fuel. In fact, the use of natural gas as support fuel in general
industrial process air streams (containing trace organic compounds other than methane) is one
of the prime design features that enhances the effective operation of TFRR units in the field,
according to the company. In general industrial settings the TFRR injects make-up fuel just
upstream of the poppet valves that admit ventilation air into the unit. Good mixing results from
having a well-located and well-configured gas injection port and a significant pressure drop
across the bed and poppets. The company is confident that they can achieve the same result
with supplemental methane injection into the ventilation air application.12
CANMET has also looked at this issue, and they agree that methane injection may be a cost-
effective method of maximizing energy yield from the system.13 The use of gob gas to enhance
heat recovery from the reactor may have to compete with using gob gas as a supplemental fuel
in the prime mover. Section 4.4 below addresses the question of which use is more cost-
effective.
4.2 Technical Issues Concerning Heat Exchangers
The following issues will influence the design of a system recovering useful energy from either a
TFRR or a CFRR installation.
4.2.1 Embedded High-Temperature Heat Exchangers
Of the three heat extraction methods described in Section 2, the embedded high-temperature
heat exchanger offers the highest quality heat in the most practical form. The other two
methods are not practical for most applications: using exhausted, oxidized ventilation air does
not provide a high-temperature medium, and extracting high-temperature ventilation air is
complex and may upset the reactor's operation.
Whichever technology requires less energy to maintain operation of the reactor itself will be able
to recover more of the input methane as useful energy. A TFRR theoretically could be
designed to produce higher temperatures than a CFRR, and thus a higher quality and more
useful form of heat for producing electricity. Such an ideal advantage would come at a high cost
if compressed air were the selected heat transfer medium, as discussed below, because higher
temperatures require the heat exchanger and transfer piping to be made of expensive materials
that can withstand high-temperature stresses. MEGTEC will probably opt for water as its heat
transfer medium.14
12 Martin Key, European Manager, Marketing and Business Strategy and MEGTEC Systems AB,
Submission from MEGTC Systems, Applicability of VOCSIDIZER, February 28,1999.
13 Telephone communication with Dr. Hristo Sapoundjiev. Research Scientist, February 22,1999.
14 See footnote 12.
26
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As shown in the following paragraphs, embedded heat exchangers introduce a number of
design questions that must be solved for each project application.
4.2.2 Handling High Temperatures
Both the thermal and catalytic reactors (but especially the TFRR) reach temperatures that
exceed the working limits of all but the more durable materials such as high-grade stainless
steel, Inconel, and ceramics. For purposes of comparison, an oxidizer (even the CFRR) can
produce working fluid temperatures in the heat exchanger (circa 1382 °F or 750 °C) that exceed,
by more than 50 °C, the maximum allowed metal temperatures of the specialized superheater
tubes in a modern steam power station. Thus, if the circulating medium in a high-temperature
heat exchanger's secondary (i.e., receiving) circuit is compressed air, the air provides little mass
to absorb the thermal shock to the embedded tubes, and the tubes will have a short useful life
unless constructed with proper materials. In many cases, the price to be paid for materials that
withstand high temperatures can be a good investment that will be repaid with increased
revenues from gas turbines that produce electricity more efficiently with a higher-temperature
working fluid. If the circulating medium is pressurized water, fewer special design precautions
are needed.
4.2.3 Placement
The designer has the flexibility to locate the heat exchanger piping (i.e., tubes, coils, etc.) at the
bed's center where the reactor maintains its highest temperature, or at cooler points along the
temperature gradient. Therefore the designer has more choices when trading off high efficiency
and performance with the high cost of exotic metallurgy. Heat exchanger placement may have
an effect on the operation of the reactor, but research performed for this report did not analyze
any possible consequences. Also, if heat exchange tubes are embedded in cooler regions of
the reactor, the working fluid's temperature may fluctuate significantly during every half-cycle as
the heat wave in the reactor approaches and retreats. The designer would have to find ways to
prevent such fluctuations from affecting the energy recovery function, for example by blending
the two flows to achieve an average and steady working fluid temperature.
4.2.4 Maintenance
Heat exchanger elements will require a higher level of monitoring and maintenance than most of
the remaining parts of the oxidizer. The reactor design should facilitate easy removal and
replacement of the more vulnerable components.
4.3 Energy Conversion Options
After the heat exchanger delivers energy in the form of pressurized hot water or compressed hot
air, the developer has several options to produce useable energy. This section briefly discusses
the more practical of these.
4.3.1 Direct Use of Thermal Energy
This is the simplest and least capital-intensive option. Its economic viability depends upon the
existence of a nearby market for thermal energy such as:
• District heating
• Industrial process heating
27
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• Coal drying
• Mine wastewater desalination
• Heating ventilation air inflows during winter months
The configuration and cost of such systems will vary greatly according to the specific use. For
example, a heat exchanger within either a TFRR or CFRR can be either air-cooled or water-
cooled. Heated and pressurized air exiting the heat exchanger can flow directly into a waste
heat boiler (or heat recovery boiler) to produce either steam or hot water. If the working fluid is
pressurized hot water it would flow to a pressurized flash tank where it converts to steam as
described in Section 4.3.2 below.
Section 5 reviews the cost and profitability of an illustrative project using pressurized hot air to
raise steam in a waste heat boiler serving a very simple district heating system located near the
mine. This example will have application in some areas of eastern Europe where district
heating systems located near active ventilation shafts are relatively common.
4.3.2 Electric Generation Using Steam Cycle
The heat exchanger within either of the two oxidizers can be effectively cooled with pressurized
water. Heat exchanger outlet temperatures up to about 572° F (300° C) are suitable for use in
heat recovery steam boilers that are either unfired or supplementary-fired to raise steam in a
waste heat boiler setting. The probable project configuration would be to feed the hot water to
an external flash chamber from which steam is captured for steam power cycle use. If sufficient
gob gas is available, a conventional waste heat boiler including a superheat stage could be
used in a supplementary-fired mode to raise the efficiency of the system.
In this case, water circulates under high pressure through the heat exchanger but is not allowed
to boil. The heated water then crosses a control valve into a pressurized tank resembling a
boiler steam drum. The tank maintains a pressure level where a portion of the water will "flash"
into steam, lowering the temperature of the water to correspond to the saturation temperature of
the steam. The steam passes into a power turbine, which converts some of its energy into shaft
power (which in turn drives an electric generator). Condensate from the power turbine's cooling
system serves to replenish water in the heat exchanger recirculation loop. It also acts as a
coolant for avoiding cavitation (the formation of cavities caused by low-pressure bubbles) and
suction loss in the recirculation pump.
In a project requiring electric generation only, the designer would choose a condensing steam
turbine with an evaporative cooling tower, either wet or dry depending upon the availability of
cooling water at the site. If a revenue-producing thermal load is available periodically or
continuously at a relatively constant demand, the turbine choice would be between an
extraction/condensing steam turbine or a back-pressure steam turbine.
Unfired Boiler.
In the case of the unfired boiler with a condensing turbine, the overall efficiency will be limited to
between 15 percent (22,750 Btu/kWh or 24,000 GJ/kWh) and 20 percent (17,065 Btu/kWh or
18,000 GJ/kWh) because of pressure limitations and the lack of superheat. The water
temperature at the heat exchanger outlet should be at least 550 °F (288 °C) under a pumping
pressure of at least 75 atmospheres (1,100 psig) to allow sufficient pressure range for flashing
while still resulting in a reasonably efficient steam cycle at a somewhat lower steam temperature
and pressure caused by the flashing.
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Fired Boiler.
In the case where gob gas or other affordable fuels are available to superheat the steam, the
cycle efficiency could reach as high as 25 percent (13,650 Btu/kWh or 14,400 GJ/kWh) if gob
gas is available in the proportion of at least 25 percent to the methane in the ventilation air. In
this case, the steam boiler could be operated at 85 tolOO atmospheres (1,250 to1,500 psig) and
with a superheat temperature of up to 950 °F (510 °C). Such design parameters depend on
cost-benefit analyses, which compare increased superheater costs with increased revenues
from additional electricity sold.
Both steam cycle cases (fired and unfired) will probably require higher capital costs and produce
lower cycle efficiencies when compared with a gas turbine case discussed below. MEGTEC
has indicated that it does not share that opinion, and instead prefers to use a large power
generating system based on high temperature and pressure steam conditions.15
4.3.3 Electric Generation Using Gas Turbine
It is likely that the preferred electric power production option will be the use of a gas turbine
operating in a cogeneration mode by recovering waste heat. Typical efficiencies for converting
thermal energy to electrical power are about 28 to 35 percent when operating under design
conditions.
A description of the gas turbine option begins at the upper left corner of Figure 7. Ambient air,
or possibly ventilation air, enters the compressor mounted on the air turbine's shaft and is
compressed to between 7 and 22 atmospheres (or about 100 to 325 psig) depending upon the
turbine design. Compressed air flows through the secondary loop of the gas-to-gas heat
exchanger in the reactor where it receives excess heat of combustion. It then returns to the
turbine's expansion section where part of its energy converts to mechanical energy and then
into electrical energy in the generator. Spent hot air then enters a waste heat boiler, which
captures useful thermal energy, if cogeneration is desired.
Des/gn Trade-Offs.
Gas turbine efficiency improves as a function of the temperature of its working fluid, but high
temperatures require high-cost exotic metals in the heat exchanger. Moreover, the efficiency of
the gas-to-gas heat exchanger in the reactor tends to decrease with high temperatures. The
design of a heat recovery system to be linked to a gas turbine requires a trade-off between
turbine efficiency and cost, and heat exchanger efficiency and cost.
Benefits of high temperatures:
• Reduced air flow in secondary circuit
• Smaller gas turbine
• Higher gas turbine efficiency
• Less supplemental fuel
15 See footnote 11 above.
29
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Ambient
air
Vent air
Gob gas to combustor
(optional)
Heated
compressed air
Air (andproducts
of combustion)
\
Air (andproducts
of combustion)
t
Heat exchanger
Oxidizer
(TFRR orCFRR)
Electricity
Steam or hot
water
Figure 7. Schematic of Cogeneration Option
30
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Penalties of high temperatures:
• Higher heat exchanger cost
• Lower heat recovery
Turbine Matching.
Modern high-efficiency gas turbine specifications call for higher turbine inlet temperatures than
are economically available from a ventilation air oxidizer. The highest practical temperature
range for the reactor outlet may be between 1382 °F and 1472 °F (750 °C and 800 °C), and that
is at or below the input needs of older and smaller gas turbines. The maximum working
temperatures for large (>25 MW) modern turbines are over 2192 °F (1200 °C), and even at
smaller sizes of <20 MW, advanced gas turbines starting to come on the market will be able to
operate at levels as high as 2102 °F (1150 °C) while achieving efficiencies well over 35 percent.
The system designer will carefully match the temperature and mass flow characteristics
available at a given mine with an off-the-shelf gas turbine. For any given gas turbine, one can
construct a performance table, or a capacity curve can be constructed with input from the
manufacturer based on the mass-flow and temperature of the hot air entering the power turbine.
The designer will also want to find a turbine with a high compressor efficiency along with other
desirable characteristics.
Currently there are about two dozen turbine models on the market in the 1.5 to 20 MW size
range. Appendix C offers a sample list of commercial gas turbines, illustrating the variety of
units available. This diversity will give a designer reasonable flexibility to match a readily
available commercial unit or a used older model with expected mass flows and temperatures at
the heat exchanger outlet.
Supplementary Firing.
The design effort will be aided greatly if the mine can supply sufficient gob gas or another
affordable fuel for supplementary combustion in the turbine to raise the working fluid
temperature to design levels, or nearly so. In some cases, the supplementary firing needs will
compete with the need to supplement vent air methane concentrations (see Section 4.4 below).
If ample supplemental fuel is available it could be possible to adjust the mass flow and firing
temperatures to correspond exactly to a given gas turbine's design specifications, allowing it to
operate at optimum efficiency. Moreover, supplemental fuel may afford an opportunity to
decrease the heat exchanger outlet temperature to some lower value that will allow less
expensive construction materials. If gob gas is insufficient to allow the gas turbine to achieve its
design temperatures, the project may either purchase natural gas or oil for that purpose, or may
operate at a derated output and a reduced efficiency.
Refinements to Efficiency.
If there is little or no demand for cogenerated steam, there may be cost-effective methods to
improve electricity production by using heat exhausted from the gas turbine. One option is to
insert an interstage heating unit at the turbine exhaust to use waste heat to raise the
temperature of pressurized air going to the reactor's heat exchanger. This would decrease the
working fluid's temperature gain in the heat exchanger and allow for an increased flow, a larger
turbine, and extra revenue. Such considerations should wait, however, until the basic process
has proven itself in field trials.
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4.4 Allocation of Scarce Gob Gas: Flow-Reversal Reactor Versus Gas Turbine
This section outlines a procedure for optimizing the allocation of scarce supplemental fuel,
usually gob gas, to the two system components that can benefit from the additional energy (i.e.]
the reactor and the gas turbine).
At most gassy mines, ventilation air is the major source of CMM emissions, with the remainder
being pipeline-quality methane and/or gob gas. A project designer will normally find that the
mine's supply of gob gas is inadequate for both (1) enabling the gas turbine to operate at its
design turbine rotor inlet temperature (TRIT), and (2) enhancing the percentage of heat
recovered from the reactor as determined by Figure 6. Before starting an analysis to allocate
supplemental fuel and/or gob gas supply to its most effective use, the analyst must determine
whether or not some amount of "support fuel" is necessary just to assure that ventilation air
methane concentrations are far enough above autothermic levels to permit some heat recovery
without threatening reactor stability. If process stability turns out not to be an issue, the next
task is to perform an optimization study that varies gob gas allocation to maximize power output.
The first step in that process is to determine how the turbine responds to a TRIT that is below
design level.
4.4.1 Determine Efficiency Impact from Decreasing Turbine Inlet Temperature
Using data from the turbine manufacturer, prepare a table or a curve for the unfired and partially
fired gas turbine cases that estimates reduced efficiency levels when TRIT falls below design
levels. Such a curve for a typical off-the-shelf, industrial frame turbine might appear as follows:
32
100
200
300
400
500
600
' F Below Design Turbine Inlet Temperature
Figure 8. Turbine Efficiency versus °F below Design Turbine Inlet Temperature -
Generic Case
Note that turbine efficiency begins to fall off dramatically when TRIT is near 90 °F (50 °C) below
design specifications. In the illustrative Figure 8, turbine efficiency would be about 20 percent at
540 °F below an assumed design TRIT of 1840 °F (or at 1300 °F), which is the assumed outlet
32
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temperature of the reactor's heat exchanger. Thus, in this case the unfired turbine (with no gob
gas allocated to its combustor) would be 20 percent efficient.
4.4.2 Optimize Use of Scarce Gob Gas
This step involves constructing a spread-sheet model with a range of cases, each representing
an increment of gob gas directed to the reactor (which corresponds to a decrement of gob gas
taken away from the turbine). Each incremental case will represent an increase in the methane
concentration entering the reactor, resulting in an increase in available energy. Using the
reactor manufacturer's recovery curves (similar to Figure 6), the analyst can estimate a heat
recovery percentage and calculate the total energy added to the compressed air working fluid.
The next steps for each case develop the mass flow of the working fluid from the reactor (air
from the turbine compressor), total heat delivered to the turbine including heat from the gob gas
as well as heat recovered from the reactor, working fluid changes due to combusting gob gas,
the TRIT with a corresponding turbine efficiency derived from the turbine efficiency curve similar
to Figure 8, and the turbine-generator's electrical output. Finally, the analyst will plot the results.
See Appendix D for a typical example of a spread-sheet model for allocating gob gas. In this
example 20% of the gob gas is being supplied to the reactor and 80% to the turbine.
4.4.3 Illustrative Example
The following is an illustration of the optimization procedure described above. The case uses
some of the same CMM assumptions used in Section 5:
• Ventilation airflow, 212,000 cfm (100 m3/s)
• Methane concentration, 0.5 percent by volume
• Gob gas (methane), 868 cfm (0.41 m3/s)
Figure 9 shows the effect on power output of varying allocations of gob gas to the reactor and
the turbine combustor. The three curves represent three concentrations of methane in
ventilation air: 0.4, 0.5, and 0.6 percent by volume.
This example shows that most of the gob gas should go to the turbine to achieve the highest
energy value for a given supply of CMM, especially when ventilation air methane concentrations
are high. At 0.4 percent methane, about a quarter of the gob gas should be directed to the
reactor, and three quarters would most productively go to the turbine combustor. If all the gob
gas were to be consumed in tne reactor, the plant would produce about 18 percent less than
optimum in all three curves.
4.4.4 Practical Implications
The optimization exercise described above gives developers a guideline to keep in mind during
the complex design of a ventilation air methane recovery plant. The exercise took place without
considering potential impacts on capital budgets or project durations of the availability and
quality of any of the CMM sources. Clearly, such case-specific parameters will influence the
conclusions indicated above.
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17000
16000
10000
10
20
30
40 -50 60
% Gob Gas to Reactor
80
90
100
•0.6% Methane
•0.5% Methane
•0.4% methane
Figure 9. Turbine Power Output at Various Gob Gas Allocations between the Flow-
Reversal Reactor and the Gas Turbine - Generic Case
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5.0 ACTUAL AND HYPOTHETICAL PROJECT CONFIGURATIONS
This section illustrates the applicability of identified ventilation air processing techniques at
actual or hypothetical gassy mines. Section 1 discussed the ideal criteria for such projects,
which are:
• Ability to accept entire flow from a single ventilation shaft;
• Exothermic, sustainable, and reliable chemical reactions;
• Simple, rugged design consistent with sound engineering;
• Technology demonstrated at large scale; and
• Profitable after byproduct recovery.
Although no current project meets all five criteria, one project meets four of five and there is a
reasonable possibility that demonstration projects in the next few years will meet all five. The
following subsections describe one actual and three hypothetical projects that illustrate the
economic potential for ventilation air mitigation.
5.1 Ancillary Use of Ventilation Air
The following cases that use ventilation air methane as an ancillary fuel exemplify both a partial
use (Appin project in Australia) and a total use (a hypothetical case featuring a mine-mouth
coal-fired power plant).
5.1.1 Partial Use of Ventilation Air in Internal Combustion Engines
The BMP project in Australia introduced in Section 2 is the only large-scale user of ventilation air
methane in the world. Proving that internal combustion engines can substitute ventilation air for
ambient air in its combustion air intake system, the project fully demonstrates the feasibility of
beneficial partial use of methane emitted from a ventilation shaft.
In 1995 BMP Collieries Division and its partners, Energy Development Limited (EDL) and Lend
Lease Development Capital (LLDC), installed two power generating projects near two
underground coal mines in New South Wales, Australia, about 80 kilometers south of Sydney.
Each facility consists of a series of Caterpillar 3516 spark-fired, 1500 rpm engines, each of
which directly drives a one-megawatt generator. Each engine/generator unit is housed within its
own acoustic enclosure. There are 40 units at the Tower Colliery and 54 units about seven
kilometers away at Appin Colliery, for a total generating capacity of 94 MW. Methane (both in-
seam and gob gas) drained from the mines, with methane content fluctuating between 40 and
60 percent or more, is the primary fuel for the project. An underground pipeline facilitates the
transfer of CMM and natural gas between the two projects.
Mine ventilation supplies combustion air for the 54 Appin engines. The ventilation air averaged
about 0.7 percent methane until recently when it diminished to about 0.3 percent. An air
filtration system removes particles from the air before it travels to the engines. Fuel value
contributed by this air stream could peak up to 10 percent of each engine's fuel needs,
amounting to 5.4 MW when all engines are running, although recently this contribution has
declined. The Appin power project consumes up to 20 percent of the mine's vented methane
emissions when operating at capacity.
35
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In the project's power sales agreement, BMP and its partners contracted to operate at full
capacity during peak periods. To accomplish this, the project must rely on natural gas to
supplement its primary fuel during periods of low gob gas flow. During off-peak periods the
project is allowed to sell all of the electricity it can produce, but, because it receives a lower
price per kilowatt hour, it relies upon only low-cost fuels (i.e., gob gas and ventilation air).
BMP reports that total capital costs (excluding the pipeline tying the projects together, and an
office building) were about US$70 million or about US$750 per kW installed. The company
does not supply detailed data on operating costs, revenues, and profits, but they express
satisfaction that the projects are achieving their financial goals.
While BMP has not identified separate capital and operating expenditures for the air substitution
part of the project, a Caterpillar spokesman stated that these were modest. They consisted of
ducting installed from just above the ventilation fan to each engine's air intake, the air filtration
system, and some additional programming at the control centers. There are no additional fans
in the ductwork because the engines generate enough suction power to move ventilation air to
their intake systems.
One can conclude that the ventilation air substitution system is a simple and practical technique
for CMM use that could be replicated at many gassy mine settings where electricity generation
using gob gas may be viable. In the Appin setting, this innovation probably yields a positive
cash flow because, for very little additional cost, the project realizes economic benefits. These
are roughly estimated as follows:
• The system's methane contribution allows the power plant to reduce natural gas
purchases to meet peak demand. For example, the plant might be able to save ten
percent of the natural gas purchased for half the plant (i.e., 27 MW). If natural gas costs
about US$20 per MWh, and there are 3600 peak hours in a year, the use of ventilation
air methane could amount to approximately US$200,000 per year in natural gas cost.
• The methane in ventilation air allows the power plant to produce incremental electricity
revenue during off-peak hours. For example, if the plant could produce ten percent extra
power during off-peak periods at an electricity rate of US$20 per MWh, that would yield
US$54 per hour times an assumed 4,400 hours per year, for an annual increase of
about US$240,000.
• If the additional capital cost for installing the ventilation air transport and processing
system was in the range of US$500,000, the payback would be slightly over one year.
5.1.2 Total Use of Ventilation Air in a Mine-Mouth Coal-Fired Plant
A coal-fired power boiler is a good example of a class of large energy consumers that have
combustion air demands roughly matching the air output of a typical mine ventilation shaft. For
example, a shaft emitting 2 mmcfd (0.656 m3/s) of methane at a concentration of 0.5 percent
has an airflow of about 400 mmcfd (131 m3/s). That is enough air to replace ambient air for a
mine-mouth coal-fired power plant rated at approximately 125 MW. This strategy is technically
feasible and would be economical if the plant already exists or will soon be built near a mine
ventilation shaft. As mentioned in Section 1, Powercoal of Australia is considering such a
project at an existing adjacent coal-fired power plant.
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For a developer to place a new coal-fired plant near a mine to compete in the current U.S.
power market, however, this option will require some careful analysis. There are at least three
levels of concern:
1. New coal plants are increasingly less able to compete in the domestic power
generation business, regardless of location. Most new capacity will utilize
natural gas-fired turbines operating in combined cycle. Moreover, coal units
in the 125 MW range illustrated herein are less cost-effective than larger
modules.
2. It may be risky for a power developer to count on these supplemental fuel
sources (ventilation air and gob gas) for the economic life of the plant,
typically 40 years. There is a strong possibility that the CMM sources may
decline or cease flowing altogether because mining operations may have
moved far from the power plant or discontinued entirely.
3. The benefits of the mine-mouth option include: inexpensive and free fuel, no
coal freight (because it consumes coal mined on site), and NOX and carbon
offsets. Can these benefits reward the power producer for locating the plant
away from more central sites when transmission lines, cooling water, and
construction labor pools are plentiful? The following analysis attempts to
address that question.
Economic Analysis
Responses to the first two concerns will depend upon case-specific circumstances and cannot
be fully addressed herein. To examine the third concern, U.S. EPA prepared a simple analytical
tool on an Excel spreadsheet. Appendix E-1 presents this model, and the results are discussed
below.
The model compared a "traditionally sited" 125 MW coal-fired power plant with an identical plant
located a very short distance from a gassy mine. The model assumed the following significant
differences for the mine-mouth location in terms of construction details:
• Extra transmission line, varying from 10 to 40 miles (16.1 to 64.4 km) long.
• Extra construction labor costs of 15 percent (accounts for travel, worker's camp expense
for remote locations, premium time, etc.).
• Dry cooling tower, which adds a small additional capital cost and a parasitic power loss.
Assumed advantages accruing to the mine-mouth plant are:
• Free fuel contribution from the ventilation air, fixed at (2 mmcfd)0.656 m3/s.
• Inexpensive gob gas (e.g., $0.60/mmBtu, varying from (1 to 3 mmcfd) 0.328 to 0.983
m3/s).
• Reduced NOX resulting from introduction of two methane sources. Credit value varies
from zero to $3,500 per (short) ton of NOx.
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• Carbon credits resulting from substituting two forms of CMM, valued from zero to $2.00
per metric tonne of CO2. Methane is equivalent to 21 times the weight of CO2 and 5 73
times the weight of carbon.16
The purpose of the model is to obtain a rough approximation of a cost/benefit relationship. The
model uses a simplified discounted cash flow format to estimate the internal rate of return (IRR)
for the additional capital invested in the mine-mouth plant, such as the transmission line and the
increased construction labor cost. Assumed financial parameters include a ten-year project life
and all equity financing. This simple model does not calculate depreciation or account for
income tax. The model also ignores the small impact of cooling tower derating from year 11
and beyond. If a potential project were to pass this screening step. A much more rigorous
analysis would be appropriate.
Preliminary Base Case Results
The following parameters were used to calculate the Base Case IRR:
Electric transmission line length: 30 miles (48.3km)
Cooling tower derate: 2 percent
Gob gas available: 2 mmcfd
Value of NOX credit: $2,500 per ton of NOX
Value of CO2 credit: $1.50 per Mt of CO2
Base Case IRR: 30.3 percent
Appendix E -1 contains a printout of the model and includes some sensitivity analyses that show
how the IRR will change as the five parameters listed above change independently. Table 3
presents those sensitivity results which show that the NOx credit may be the dominant
parameter if prices remain in the indicated range.17 When all of the five parameters are at the
most optimistic end of their range (i.e., the "Best Case"), the resulting IRR is 78.3 percent. The
results clearly demonstrate that the project is heavily dependent on financial incentives arising
from environmental benefits.
16 Appendix F provides background on greenhouse gas emissions trading as well as a sampling of
several known trades.
17 Forecasting the future price of NOX offsets is complicated by a recent U.S. Court of Appeals ruling
which struck down U.S. EPA rulemaking for ozone compliance in 2003. Some market observers say
that this action does not affect the 8-hour standard underlying NOX trading. Others feel that the order
will depress the market, and yet another group predicts that the market uncertainty favors offset
purchases over investing in pollution control equipment. Source: Airtrends, Volume 2, Issue 17, May
1 ggg by Natsource.
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Table 3. Results of Sensitivity Analysis
Mine-Mouth Coal-Fired Plant
(base case bold)
Transmission Line
(miles)
Gob gas (mmcfd)
Derate (%)
10
20
30
40
1.0
2.0
3.0
0
2
IRR%
41.45
35.19
30.29
26.32
22.75
30.29
37.47
34.00
30.29
NOX credit
($/ton)
CO2 credit
($/Mt)
0
1000
2000
3500
0.00
0.50
1.00
1.50
2.00
Best Case
Worst Case
IRR%
9.60
20.55
30.29
43.87
25.14
26.88
28.59
30.29
31.97
78.29
-1.48.
5.2 Principal Use of Ventilation Air
The two vendors of flow-reversal reactors, MEGTEC and CANMET, supplied U.S. EPA with
some preliminary cost estimating information on a system rated at 212,000 cfm (100 m3/s) of
mine ventilation air. It is important to understand that cost data supplied for a general report
such as this will be approximate and subject to change for the following reasons:
• Neither vendor has built and operated a full-scale unit appropriate for use at a gassy
coal mine.
• Predicting the economics of energy recovery and marketing from reverse-flow oxidizers
is difficult because the need to mitigate local pollution, rather than to compete in the field
of energy supply, has driven the justification of all systems installed to date.
• System costs will vary greatly from one application to another due to the variation in
physical and economic parameters at each site.
• Each vendor applied a different and unknown standard of conservatism to the estimates.
• Neither vendor is willing to reveal sensitive and confidential cost estimating information.
Nevertheless, there is cost information to build reasonable models that can suggest the
economic viability of either the TFRR or the CFRR operating in the domestic U.S. marketplace.
A review of the limited cost data showed that there is no clear difference between the two
systems' costs, and it would be misleading to compare one against the other because of an
incomplete understanding of the underlying case-specific design variables. Therefore, the
following illustrative cases consider a "generic" design that blends the two systems and
obscures any differences in performance, capital costs, and operating and maintenance costs.
39
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U.S. EPA has supplemented the vendor-supplied information with reasonable and conservative
estimates of project operating conditions, financial assumptions, revenues, and costs.
The following two hypothetical cases exemplify the use of either a TFRR or a CFRR using
ventilation air as its primary fuel to generate electricity and/or thermal energy in a small power
plant located at a gassy mine. The two cases are:
A. A flow-reversal oxidizer producing electric power and cogenerated steam with
either a fired or unfired prime mover.
B. A flow-reversal oxidizer producing only steam.
5.2.1 Project A. Principal Use of Ventilation Air in a Flow-Reversal Oxidizer with a Gas
Turbine Cogeneration Plant
This hypothetical project uses a single flow-reversal unit rated at 212,000 cfm (100 m3/s) to
capture most or all of the emissions from a nearby ventilation shaft at a gassy mine in the U.S.
Project A relies on the methane captured from the ventilation shaft as its primary source of
energy, and it relies on a limited supply of gob gas to enhance heat recovery in the oxidizer. An
estimate of heat recovery enhancement is based on the slope of a section of the curve in
Figure 6. As methane concentration increases due to gob gas injection, the total source of fuel
increases as does the percent that can be recovered. In the "unfired case" all available gob gas
goes into oxidizers, but in the Tired case" part of the gob gas finds a use in the gas turbine to
raise the working fluid temperature and make better use of the turbine's high-temperature
capability. The fired case assumes that a substantial amount of methane in the form of gob gas
is available to the project developer—a situation that may exist in several gassy mines in the
U.S. The unfired case assumes a lower gob gas flow, and directs all of it into the reactor to
enhance heat recovery.
A waste heat boiler placed at the gas turbine exit for both cases recovers thermal energy in the
form of slightly superheated steam for local heat use.
This project will satisfy three of the five criteria listed above: can accept entire flow from a single
ventilation shaft; has an exothermic, sustainable, and reliable chemical reaction; and has a
simple rugged design consistent with sound engineering. As of the publication date of this
report, the fourth criterion has not been met: there is no large-scale demonstration of the
technology. In the TFRR case, however, several units in the field have operated on methane
(natural gas) for discrete periods, and in the CFRR case there will be field trials as early as 2000
in Nova Scotia. The purpose of this case study is to apply a simple test of the fifth criterion.
That is, using the preliminary cost estimates and reasonable assumptions, is Project A profitable
after byproduct recovery?
Appendix E -2 contains a printout of a cash flow model for both the fired and unfired versions of
Project A. The following paragraphs explain some of the assumptions underlying the model.
Engineering Considerations
This report selects a configuration for Project A based on the assumption that the hypothetical
designers would have followed the concepts developed in Section 4 to specify components.
The designers would perform a cost-benefit analysis to select the reactor outlet temperatures
and heat exchanger materials. They would calculate airflow mass and select a reconditioned
used gas turbine model requiring lower inlet temperatures in an attempt to optimize project
40
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economics. Because of the wide range of possible mine conditions, this report relies on
representative parameters and turbine system configurations that are somewhere in the middle
range of expected field situations for a gassy coal mine. Most of the selections are
conservative.
Two factors that the analysis does not address are the decreasing economic lives of ventilation
shafts and the development of new bleeder shafts. A CMM producer contacted for this report18
commented that there are trends within the industry toward (1) employing small-diameter
bleeder shafts in which methane concentrations may be one percent or more and airflows are
lower and (2) moving ventilation fans every two or three years. These two related trends will
tend to offset each other in terms of affecting profitability, as follows:
Additional costs will arise because shorter vent shaft lives will require
periodic costs for moving the energy recovery plant. Other costs
would fall, however, due to decreased investment for smaller reactors
and lower operating costs (e.g., reduced fan power needs). Project
revenues will increase because higher methane concentrations
produce more recoverable energy.
If these trends become widespread they may bolster ventilation air methane recovery and use
projects by increasing revenue-to-plant investment ratios. Moreover, system designers can
mitigate the costs and interruptions associated with frequent moves by designing plant
components to be modular, portable, and easy to reassemble.
Both the unfired and fired cases use the following assumptions:
• Ventilation air flow
• Methane concentration
• Methane flow
• Percent heat recovered
• Heat exchanger outlet temp.
• Heat exchanger air mass flow
• Parasitic loss, fan, etc.
• Operating hours/year
Unfired case assumptions, base case:
• Gob gas available (as methane)
• Gob gas use
• Calc. heat avail, for turbine
• Turbine efficiency - unfired
• Gross electrical output
• Calculated boiler rating
212,000 cfm, (305 mmcfd or 100 m3/s)
0.5 percent
1059 cfm (0.5 m3/s)
Based on Figure 6; depends on gob gas input
1,292°F(700°C)
88.16 Ib/s (40 kg/s) + injected gob gas allowance
1,100kW
7,884 electric, 6,570 steam
424 cfm (0.6 mmcfd or 0.2 m3/s )
100% in reactor
71.52 mmBtu/h (75.39 Gj/h)
22 percent
4,610 kW(.)
11,434kW(t)
18
From a memorandum from Joseph A. Zupanick, September 1999.
41
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Fired case assumptions, base case:
• Gob gas available (as methane) 868 cfm (1.25 mmcfd or 0.41 m3/s )
• Gob gas use 40% in reactor; 60% in turbine
• Calc. heat avail, for turbine 97.46 mmBtu/h (102.74 Gj/h)
• Turbine efficiency - fired 28 percent
• Gross electrical output 7,996 kW(e)
• Calculated boiler rating 10,896 kW(,)
Turbine capacity requirements are based on a dynamic calculation in the model. The analyst
then rounds off to the nearest matching capacity of an off-the-shelf unit. An ideal selection
would be a reconditioned older turbine designed for a lower firing temperature because it would
achieve a better efficiency and an output closer to its nameplate rating. This is especially true
for the unfired case.
Cost Assumptions
These cost estimates are based on information supplied by both vendors plus conservative
estimates supplied by the contractor. Turbine-generator costs assume a reconditioned older
unit and include a heat recovery boiler.
• Reactor cost +15% contingency, 212,000 cfm $3.15 million
(100 m3/s) unit, 0.5% methane
• Turbine-generator capital cost - per kW installed $650
• Project "soft costs" as percent of installed cost 25%
• Turbine-generator maintenance cost 0.0035/kWh
• Miscellaneous annual operating cost 3.2% capital
• Cost of gob gas per 1.055 GJ or mmBtu $0.60
Revenue Assumptions
• Electric sales price: Low: 3.0 cents/kWh High: 4.5 cents/kWh
• Thermal energy sales price: Typical price = $3.00/mmBtu, or about 1.0 cent/kWh(t)
Carbon Offset Assumptions
• Vent and gob methane destroyed - unfired case 3,760 Ib/h (1,706 kg/h)
• Vent and gob methane destroyed - fired case 4,908 Ib/h (2,227 kg/h)
• Global warming potential: methane versus CO2 21
• Assumed value of CO2 per Mt ' $1.50
Results
Appendix E-2 contains the base case version for Project A, both unfired and fired. It also
presents a limited number of sensitivity analyses that show how the IRR will change as five
parameters change independently. Table 4 summarizes the base case and sensitivity results.
It appears that Project A will pass the profitability test, providing pricing conditions are favorable.
For example, a power price of $0.035 combined with a greenhouse gas credit of $1.50 per Mt of
CO2 equivalent could allow the fired case to show a 29 percent IRR. It also appears that the
42
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fired case is reasonably resistant to selected parameter changes. If one of the following
changes took place: only half the gob gas was available; if the electric price was only $0.03; if
the methane concentration dropped to 0.4 percent; or if the carbon credit was only $1.00, the
fired case would still be financially attractive. The unfired base case shows a 20 percent IRR,
and it would be in, or close to, the profitability range if any one of the five parameters were to
improve by one increment shown on the table.
Table 4: Results of Sensitivity Analysis
Project A: Flow-Reversal Oxidizer with a Gas Turbine Cogeneration Plant
(base case bold)
Capital cost
Electric price
Gob gas
Methane
concentration
Carbon credit
%+or-
-20
0
+20
$/kWh(e)
0.03
0.035
0.045
cfm (m3/s)
424/0.20
635/0.30
869/0.41
%
0.4
0.5
0.6
$/Mt CO?
0.00
0.50
1.00
1.50
2.00
% IRR
fired
44.6
29.3
19.2
23.8
29.3
40.2
25.0
27.3
29.3
24.6
29.3
33.3
18.0
21.8
25.6
29.3
33.0
% IRR
unfired
33.3
20.2
11.4
16.7
20.2
26.9
20.2
22.9
25.3
14.9
20.2
24.2
9.4
13.1
16.7
20.2
23.6
5.2.2
Project B. Principal Use of Ventilation Air in a Flow-Reversal Oxidizer in a Waste
Heat Boiler Plant
Hypothetical Project B uses a single flow-reversal unit rated at 212,000 cfm (100 m3/s) to
produce steam. Pressurized air from an electrically driven compressor goes through the heat
exchanger in the reactor, gains heat, and releases it in a waste heat steam boiler. This option is
43
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useful when the mine is located near a stable thermal market such as a district heating system
or a brine evaporation plant. Project B has a much simpler configuration than Project A, and its
capital cost is substantially lower. As with Project A, the developer has two options if a
substantial amount of gob gas is readily available:
• To improve the energy yield from the heat exchanger by increasing the methane
concentration, or
• To increase the amount of steam produced by firing gob gas in the boiler.
This illustration assumes that methane in gob gas is available at the rate of about 50 percent of
the methane flowing in the ventilation air. Appendix E-3 contains a printout of a cash flow model
for Project B. The following paragraphs explain some of the assumptions underlying the model.
Engineering Considerations
It is a simpler task to allocate scarce gob gas for Project B because the heat exchanger yield
will increase exponentially with supplemental fuel while the boiler yield would only increase
linearly. The developer presumably will direct all supplemental methane into the reactor to
enhance both the heat quantity and heat recovery percentage based on the curve in Figure 6.
Therefore, the economic analysis for Project B only addresses the unfired case.
Project B uses the following assumptions for the base case:
• Ventilation air flow 212,000 cfm (305 mmcfd or 100 m3/s)
• Methane concentration 0.5 percent
• Methane flow, ventilation 1059 cfm (0.5 m3/s)
• Percent heat recovered Based on Figure 6; depends on gob gas input
• Gob gas available (as methane) 0.76 mmcfd (527.8 cfm or 0.25 m3/s)
• Gob gas use 100% in reactor
• Heat exchanger outlet temp. 1,112° F (600° C)
• Heat exchanger air mass flow 185.2 Ib/s (84.0 kg/s)
• Parasitic loss, fan, etc. 900 kW
• Operating hours per year 7,884
• Calculated heat available for boiler (80.54 mmBtu/h) 84.9 GJ/h
• Calculated boiler production 18,878 kW(,)
Cost Assumptions
Some of the reactor cost estimates used in Project A are applicable for Project B. There may
be a reactor cost reduction due to this project's assumed lower temperature in the heat
exchanger, 1112° F versus 1292° F (600° C versus 700° C), but it is not reflected here.
• Reactor cost +15% contingency, 212,000 cfm $3.15 million
(100 m3/s) unit, 0.5% methane
• Boiler and ancillary equipment $0.944 million
• Project "soft costs" as percent of installed cost 25%
• Miscellaneous annual operating cost 3.2% capital
• Cost of gob gas per mmBtu or 1.055 GJ $0.60
• Power cost per kW/hr $0.05
44
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Revenue Assumptions:
• Thermal energy sales price: Typical price $3.00/mmBtu, or about 1.0 cent/kWh(t)
Carbon Offset Assumptions:
• Ventilation methane/hr 2698 Ib (1224 kg)
• Gob methane/hr 1349 Ib (612 kg)
• Global warming potential: methane versus CO2 21
• CO2 equivalent avoided per hour: 1.836 x 21 38.56 Mt
• Assumed value of CO2 per Mt $1.50
Appendix E-3 contains a printout of the base case model for Project B. It shows an IRR of 33.3
percent, and it includes some sensitivity analyses that show how the IRR will change as four
parameters change independently. Table 5 presents those sensitivity results.
Project B also has an excellent potential for profitability at a site where conditions are favorable.
If the market for thermal energy could support a price of $0.01 per kWh(t) and the project could
earn carbon dioxide credits of $1.50 per Mt, the project might show an IRR of about 33 percent.
Even if the capital cost were to rise by 20 percent the project's IRR would come close to 25
percent. The IRR would remain above 25 percent if gob gas suffered a 25 percent shortfall or if
ventilation air methane dropped to 0.44 percent. The project could only accept about a 14
percent drop in the thermal price before falling below 25 percent IRR, but that drop could be
restored with a $0.70 increase in the price of a metric tonne of carbon dioxide.
45
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Table 5: Results of Sensitivity Analyses
Project B: Flow-Reversal Oxidizer with a Steam Plant
(base case bold)
Capital cost
Steam price
Gob gas
Methane
concentration
Carbon credit
%+or-
-20
0
+20
$/kWh(.)
0.08
0.1
0.12
cfm (m3/s)
265/0.125
530/0.25
794/0.375
%
0.4
0.5
0.6
$/Mt
0.00
0.50
1.00
1.50
2.00
% IRR
47.9
33.3
23.5
21.0
33.3
45.4
20.5
33.3
46.0
20.4
33.3
45.8
14.3
20.8
27.1
33.3
39.5
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6.0 CONCLUSIONS
CMM recovery and use is a function of its concentration and takes place in the reverse order of
its occurrence in the field. In other words, the dominant form of CMM (i.e., that contained in
ventilation air) has the least demand compared to gob gas and pipeline-quality CMM. Thus, the
search for viable methods that use or at least destroy a major percentage of this source of
greenhouse gas becomes extremely important to those who wish to mitigate methane
emissions from coal mines effectively and economically.
6.1 Ancillary Uses
This report has made a distinction between technologies that use ventilation air as an ancillary
fuel and those that use it as a primary fuel. Ancillary uses depend upon a nearby power facility
or similar energy consumer that uses another fuel as its primary fuel. Except for the mine-
mouth coal-fired plant, ancillary uses normally offer a partial destruction of ventilation air
emissions. The leading ancillary use example is the Appin Colliery in Australia, which
consumes up to 20 percent of the methane emitted from its ventilation shaft in 54 internal
combustion engines. Appin's primary fuel is CMM (in-seam gas and gob gas) supplemented
with natural gas, and its secondary fuel is ventilation air substituted at low cost for ambient
combustion air. This project is very cost-effective, and one can expect to see more examples of
partial or secondary ventilation air uses in new settings where physical and economic conditions
are conducive to establishing a facility based on the primary fuel, and where the use of
ventilation air is ancillary.
6.2 Technical Feasibility of the Principal Use of Ventilation Air without Supplemental
Fuel
Two ventilation air processors identified in the report are in somewhat different stages of
development. MEGTEC's TFRR (VOCSIDIZER) is in use at over 600 locations throughout the
world, but only one facility operated exclusively on ventilation air, and the results of that
demonstration are not yet available. Several of MEGTEC's other units operate intermittently on
dilute natural gas when concentrations of target compounds (i.e., industrial volatile organic
compounds) are insufficient to maintain the reaction. CANMET's CFRR, developed expressly
for mine ventilation air, is operating at bench scale and will go into an industrial scale
demonstration early in 2000. U of U analysts performed a technical assessment of these two
reactors using numerical modeling, and they were able to draw significant conclusions:
• Both technologies are technically able to oxidize dilute methane in ventilation air.
• Both technologies will produce useable energy from a heat exchanger operating at a
useful temperature range.
• CFRR and TFRR modeling results favored the CFRR, primarily because it can sustain
operation at a lower concentration. However, MEGTEC has supplied field data showing
that their TFRR will be autothermic at similarly low methane concentrations.
• Whichever unit has a lower autothermal concentration limit will recover a somewhat
higher percentage of useable energy from the reactor.
U.S. EPA Headquarters Library
Mail code 3201
1200 Pennsylvania Avenue NW
Washington DC 20460 47
-------
These independent observations, coupled with the fact that flow-reversal reactors have
operated successfully, give confidence that regenerative flow-reversal technology with or
without a catalyst will achieve success during commercial-scale field trials using actual mine
ventilation air.
6.3 Economic Viability of Flow-Reversal Reactors
Section 5 of this report presented two preliminary economic analyses of project scenarios using
a flow-reversal reactor coupled to: (1) a gas turbine cogeneration facility, or (2) a waste heat
boiler. Both hypothetical projects appeared to be in or close to the profitability range when
operating in appropriate energy markets while taking advantage of modest credits for the
greenhouse gas emissions that the projects would mitigate. Except for the cogeneration unfired
case, the economic models showed the projects to be resilient to selected unfavorable changes
in major revenue, cost, or methane supply assumptions.
A series of assumptions, and not actual field data, provided the basis for these economic
studies. Therefore, it is too early to rely on them with total confidence. They are a source of
hope, however, that solutions for elimination of methane emissions from ventilation air shafts
may be affordable in the near future.
6.4 Impact of Carbon Credits
It is useful to consider the implications of the assumed value of carbon credits with respect to
the economic modeling conducted for this analysis. In the fired cogeneration base case,
including the value of carbon credits in the economic analysis results in an attractive internal
rate of return of 29.3 percent. Removing those credits leaves the project with an IRR of 18.0
percent, which is less than adequate to attract investors. Therefore, the project would only
move forward if one of the other cost or revenue parameters were more favorable or if a carbon
credit of about $1 per Mt of CO2 were available.
In both the thermal case and the unfired cogeneration case (base cases) project IRRs are 33.3
percent and 20.2 percent, respectively, when carbon credits are included in the economic
analysis. Removing those credits, however, reduces the IRRs to 14.3 percent and 9.4 percent
respectively, which are low enough to render these illustrative projects economically unattractive
and too risky from the standpoint of a developer in the absence of the full $1.50 carbon credit
value.
Curiously, there is good news whether project developers can move a ventilation air methane
use project forward without carbon credits, or if they need to include them in their financial plan.
With IRRs in the neighborhood of 25 percent, a significant number of fired cogeneration
applications should be economically attractive to investors on their own, regardless of how the
emerging carbon credit market develops. In addition, when that market does mature, the
carbon credits accruing to both the thermal and cogeneration applications will improve the
economics of many of the available projects to the degree that they are viable as well. Thus,
regardless of the direction in which a carbon credit market evolves, technologically and
economically feasible options for productively using ventilation air appear to be available.
48
-------
APPENDIX A
TECHNICAL EVALUATION OF VENTILATION AIR OXIDATION
PROCESSES
A-1
-------
Appendix A. Technical Evaluation of Ventilation Air Oxidation Processes
The University of Utah's Chemical Engineering and Fuels Department (U of U) prepared a
technical assessment of the thermal flow-reversal reactor (TFRR) and catalytic flow-reversal
reactor (CFRR) chemical reactor processes using computer simulation techniques. This
Appendix provides a detailed review of the numerical simulation modeling developed to perform
the technical assessments.
Since operations of the thermal and catalytic flow-reversal reactors are identical, the following
paragraphs describe only the CFRR model in detail. From a chemical engineering viewpoint, if
a reaction takes place in a single phase it is considered homogeneous. The TFRR reaction
takes place in the gas phase; therefore, the TFRR has also been called the homogeneous flow-
reversal reactor. In the CFRR, the reaction takes place in the presence of a catalyst. Because
the reactant resides in the gas phase and solid catalyst particles are involved, this is considered
to be a heterogeneous reaction. Such distinctions, however, have no impact on the analysis of
the two processes.
Reaction Stoichiometrv. Equilibrium, and Thermochemistry
The stoichiometry of methane oxidation may be simply represented by the following equation:
CH4 + 2O2 -» CO2 + 2H2O (1 j
The standard heat of reaction at any temperature can be calculated using:
°-461xl°
AH = -810267 + 28.417- 25.56 xlO'3T2 + 6xl0'673 +
mol CH4
The temperature dependency of the thermodynamic equilibrium constant is described by:
IK- A °'231 97458 T -3r ~7 2
—2T~+ 3' 17n ~3-074xl° + 3-61xl° (3)
The equilibrium conversion of methane is independent of the pressure of operation. For a
stoichiometric feed of methane and oxygen, the equilibrium conversion at temperature 7 may be
shown to be:
Since the values of K range from « 10156 at 0 °C to « 1023 at 1600 °C, K » 1 and we may
conclude that xe ~ 1 for all temperatures considered in this work. Thus there are no equilibrium
limitations to the oxidation of methane.
Kinetics of CH. Oxidation
The performance of two types of catalysts for methane oxidation was investigated in this study.
Anderson et al.1 have published the kinetics of methane oxidation over base metal catalysts.
They correlated the oxidation of CH4 over supported copper chromite by:
1 Anderson, R.B.; Stein. K.C.; Feenan, J.J.; Hofer, L.J.E. Ind. Eng. Chem. 1961, p 809.
A-2
-------
where r is the intrinsic reaction rate in gmol/(cm3 catalyst-sec) and CCH is the molar
concentration of methane in gmol/cm3. The values of A and E were reported to be 10487 sec"1
and 23.1 kcal/gmol, respectively. The same authors have reported the kinetics of methane
oxidation over noble metal catalysts. In particular, the rate of oxidation over Pt/AI2O3 could also
be described by a first-order rate expression with A = 10735 sec"1 and E = 23.5 kcal/gmol.
The oxidation of methane can also take place homogeneously. Westbrook and Dryer2 have
described the global kinetics of this reaction by:
(6)
Two sets of values have been reported for A and E/R: A - 1.3 * 108 sec"1 and E/R = 24358; A
= 8.3 x 105 sec1 and E/R = 15,098.
Differential Material and Energy Balances for the CFRR
The CFRR reactor model was developed under the following assumptions:
• Plug flow of gas, flat velocity profile across the reactor diameter, no entrance or end
effects.
• Axial and radial dispersion of heat and mass are negligible.
• Intraparticle (internal) and interparticle (external) gradients of concentration and
temperature are absent. Thus the global and intrinsic rates of the reaction are the same.
• The temperature and the concentration profiles of all the species are continuous across
the transition from inert bed to the catalyst bed and from the catalyst bed to inert bed.
• No reaction takes place in the gas phase of the entire reactor.
Heat released due to the reaction occurring in the pellet is transferred from the surface of the
pellet to the gas by convective heat transfer. Consider the reactor just before flow reversal
takes place. A certain amount of gas is trapped within the reactor with a given temperature and
methane concentration profile. If flow reversal is assumed to take place instantaneously and
the gas flow rate is high, the volume of unreacted methane and air trapped inside will be swept
out of the reactor and released immediately, and it will have no effect on the next cycle.
However, the solid inert media and catalyst pellets remaining within the reactor retain their
temperature profile at the end of the half-cycle, and this becomes the initial solid temperature
profile for the next half-cycle.
Since no reaction takes place in the inert beds and the accumulation of methane in the void
spaces is small in comparison with the methane passing through the reactor in one half-cycle,
the mass balance for methane in this section need not be solved.
The following equations describe the energy balance for the CFRR's inert beds. For each of the
beds (inert or catalytic) there are mass and energy balances. The mass balance addresses
only the methane while the energy balances are on the gas and on the solids.
Westbrook, C.K.; Dryer, F.L. Combustion Science, and Tech. 1991, 79, p 97
A-3
-------
Energy Balance
Gas phase
ar ar
. _.
-T
Solid phase
Catalytic bed
Equation 9 describes the CFRR's mass balance on methane in the gas phase.
dx dx _
Energy balance
Gas phase
«n+an.0.VI-;_r-, (10)
dt' dz* cV c ; v '
Solid phase
The nondimensional variables are:
„ _ ^CH4 ~ CCH4 T'=J1 T'=L_ 7'=i #' = '
r» ' T ' c T ' / ' fl
UCH4 'O '0 L °
The model parameters are:
_ 8 , e =
Pg^ eb PsCps PsCps70 C°H< eb us
Equations are coupled hyperbolic partial differential equations (PDEs). To solve the PDEs, we
need three initial conditions and three boundary conditions for x,T*, andTr*. They are as
follows:
Initial conditions:
x(z,o)=0
rt,o)=i
Tc*(z,o)= solid temperature profile from the previous cycle
Boundary conditions:
x(o,0=o
/ \ * '
r (0,0=1
A-4
-------
The set of initial and boundary conditions are consistent.
Differential Material and Energy Balances for the Homogeneous Reactor
Inert beds
Energy balance
Gas phase
Solid phase
Homogeneous reactor
Gas phase mass balance
f+f=8r° (18)
Gas phase energy balance
^r + ^-r = yrg <19)
dt dz
The initial and boundary conditions remain the same as those for the catalytic case (equations
(14) and (15)).
Data Required
The reactor model as developed requires input data. The data requirements and equations
used are explained in this section.
• Pressure of the feed gas. The pressure drop through the reactor is estimated using
the Ergun equation3:
AP
150(1-S>
(20)
The inlet pressure is set at P0 = Pexit + AP Pa.
• Initial temperature of the feed gas (K).
• Temperature profiles of the gas and solid phases (K).
• Initial composition of CH4 (in volume %).
• Volumetric flow rate of the feed gas under standard conditions (25 °C, 1 atm), V0
m3/s.
'' Bird, R.B.; Stewart, W.E.; Lightfoot, E.N. Transport Phenomena, Wiley and Sons, 1960.
A-5
-------
• Length of the three sections: L1f L2, L3; L = U + L2 + L3 (m).
• Diameter of the reactor, d{ (m).
• Diameter of the solid pellets in the inert and catalytic sections, dpi and dpc, (m).
Physical Properties4
Gas phase
Concentration of methane in the feed: CL =
- — —
CH' 100Rg7 m3
o =.
Q r^ ^r 3
Density: RoT m
where Rg = 8314 Pa-m3/(kmol-K), M = 28.966 kg/kmol
I^SxIO^T05039 kg
Viscosity: u = -- —
1 + 108.3/7 m-s
3.1417x10-4707786 W
, .1 .••..
Thermal conduct,v,ty:
Specific heat capacity: ^ = 3.355 + 0.575 x10"3 7 _°-0162x1°5
J/. 70
Row rate: ^273.15 P0
Mass velocity: Gm = pffus = constant
The temperature-dependent gas-phase properties are evaluated at the average of the inlet gas
temperature and the maximum temperature, Tmax, which is the sum of the initial catalyst
temperature and the adiabatic temperature rise:
(-AHV,
_
22.4GmCM
Solid phase
Inert beds:
Density: pi = 4070 kg/m3
Perry, R.H.; Green, D.; editors Perry's Chemical Engineering Handbook, Sixth Ed. McGraw Hill.1994.
, A-6
-------
Specific heat capacity: Cpi = 91 0 J/(kg-K)
Catalyst beds:
Density: pc= 1250 kg/m3
Specific heat capacity: Cpc = 1060 J/(kg-K)
The specific surface area is given by:
a, = 6/dpy m2/m3 (22)
The bed voidage may be predicted using:
bj = 0.39 + 0.07 + 0.54
(23,
The heat transfer coefficient was found using the /-factor analogy between heat and mass-
transfer for packed beds:
hcj= 0.458 i at w/(m.K) (24)
In equations (22) to (24), subscript; refers to the catalytic section (c) or the inert section (i).
The rate expressions are also expressed in nondimensional form. Equations (5) and (6)
become:
r = exp
r = exp
r:
c
^ <*»
' c
•\0
'CH,
1 P kmol
TP m3-s
(26)
where 7t = E/RgT0 andr| =ln>4-7:. In equation (26), a is the ratio of the molar flow rate
oxygen to that of methane in the feed.
These coupled partial differential equations with the appropriate boundary conditions were
solved using a numerical procedure called the Method of Lines. All of the computer programs
for the solution were developed at the University of Utah.
Parameters Used
Reactor length = L = 1.5 m
Bed heat capacity = ps Cps = 1,360,000 J/(m3K)
Volumetric heat transfer coefficient = hc-a = 100,000 W/(m3K)
Bed void fraction = eb = 0.65
Cycle time = tcyc = 200 seconds (the flow is reversed every 100 seconds)
Inlet gas temperature = 20°C
Superficial gas velocity = us = 0.7 m/s (interstitial velocity = 0.7/0.65 = 1.08 m/s)
Rate law = r= 2.53x1010-exp[-45000/(1.987-7)]-CA, kmol/(m3s)
A-7
-------
Inlet CH4 concentrations = 0.06 -1 mol%
Model Analysis
The model output was CH4 conversion, gas-phase temperature, and solid-phase temperature,
as a function of position within the reactor and time. The key difference between the models for
the two reactors is the location of the reaction. In the TFRR, the reaction and heat release
takes place in the gas phase, whereas in the CFRR the reaction occurs on and within the
catalyst. In either case, the solid phase is the heat storage device releasing heat to the cold,
incoming gas and extracting the exothermic heat of reaction from the completely converted gas.
However, in the case of the CFRR, the reaction is limited to the section that houses the catalyst.
On the other hand, the reaction in the TFRR takes place wherever the temperature is high
enough (« 1000°C).
The model parameters that govern the solution process are:
• Physical properties of the gas and solid: density, specific heat capacity.
• Reaction: rate law, heat of reaction.
• Reactor: length, voidage, diameter, specific surface area of solids per unit reactor
volume (a).
• Operating conditions: gas flow rate, initial gas temperature, inlet CH4 concentration,
inlet solid temperature profile.
• Cycle time, tcyc : the flow is reversed every tcyc/2 seconds.
For a given system, the physical properties and reaction characteristics are fixed by the
materials involved. The gas flow rate and the initial gas temperature are also fixed by process
conditions. For a reactor containing a monolithic or palletized catalyst or inert heat transfer
medium, voidage and a are also fixed. Thus, the only parameters to be chosen are: reactor
length, diameter, initial solid temperature, and cycle time. Eventually, after a certain number of
cycles, a cyclic steady state is established, wherein:
• The gas exits at a temperature Texit = T0 + Tad .
• The solid temperature profile is invariant upon flow reversal.
• The conversion is unity.
This corresponds to a successful reactor operation. The initial solid temperature profile is
chosen to ensure that the process is not a non-starter (I.e., the reaction is initiated). The cycle
time is chosen so that reactor blow-out does not occur. If t^ is too long, the heat front or
temperature wave is carried out of the reactor leading to extinction. On the other hand, if tcyC is
too short, there will not be enough energy to sustain the reaction and extinction will eventually
occur.
A-8
-------
Results
Thermal Flow-Reversal Reactor
The success of the operation for various inlet CH4 concentrations was monitored in accordance
with the criteria stated previously. For each cycle, the average temperature and conversion
over tcyc seconds were computed by integrating the instantaneous gas-phase exit temperatures
and conversions. These are plotted in Figure 1.
. Methane Cone. = 1.00%
. Methane Cone. = 0.50%
- Methane Cone. = 0.35%
. Methane Cone. = 0.30%
- Methane Cone. = 0.20%
- Methane Cone. = 0.10%
- Methane Cone. = 0.06%
10
20 30
Cycle number
50
Figure 1. Exit Gas Temperature from a TFRR as a Function of Cycle Number
Figure 1 clearly shows that the operation is autothermal down to 0.35% CH4 in the inlet. At
0.3% CH4 and below, the exit gas temperature falls off to 20°C and the reactor is completely
cool. Plots of the gas. conversion for concentrations below 0.35% are shown in Figure 2, below.
The conversion steadily falls to zero with increasing cycle number.
A-9
-------
11
21 31
Cycle number
• Methane Cone. = 0.35%
. Methane Cone. = 0.30%
. Methane Cone. = 0.20%
. Methane Cone. = 0.06%
Figure 2. Exit Conversion from a TFRR as a Function of Cycle Number
A-10
-------
Catalytic Flow-Reversal Reactor
The CFRR simulation assumed conditions identical to those employed in the TFRR analysis,
except that in the CFRR simulation, the initial temperature profile was a triangular function with
a maximum temperature of 425°C at the bed center. The results clearly show that the CFRR
blows out only at about 0.1% CH4 in the feed inlet (Figures 3 and 4).
450
400
Methane Cone. = 1%
Methane Cone. = 0.3%
Methane Cone. = 0.1%
Cycle Number
Figure 3. Exit Gas Temperature from a CFRR Modeled under the
Same Conditions as the TFRR
U.S. EPA Headquarters Library
Mail code 3201
1200 Pennsylvania Avenue NW
Washington DC 20460
A-11
-------
Methane Cone. = 1%
Methane Cone. = 0.3%
Methane Cone. = 0.1%
Cycle Number
Figure 4. Exit Conversion from a CFRR Modeled under the
Same Conditions as the TFRR
Conclusion
The University of Utah conducted computer model simulation of the TFRR and CFRR reactors
under identical conditions except for the initial temperatures for both the TFRR and the CFRR.
Figures 1, 2, 3, and 4 show that the TFRR requires a CH4 concentration of 0.35% to remain
autothermic, while the CFRR can remain autothermic almost to a level of 0.1% CH4. Design
assumptions could lead to differences between modeling results and field trials, so actual field
trial results would be more reliable indicators of performance.
A-12
-------
Nomenclature
A Pre-exponential factor, s
-1
3
C Molar concentration, kmol/m
Cpg Gas-phase specific heat capacity, J/kmol K
Cps Solid-phase specific heat capacity, J/kmol K
dp Particle diameter, m
E Activation energy, J/kmol
Gm Gas mass velocity, kg/s
hc Heat transfer coefficient, W/m2K
K Thermodynamic equilibrium constant, (-)
L Length of the reactor, m
r Volumetric rate of reaction, kmol/m3s
Rg Universal gas constant, J/kmol K
TO Inlet gas temperature, K
Tg Gas-phase temperature, K
Ts Solid-phase temperature, K
us Superficial velocity, m/s
x Conversion, (-)
Xe Equilibrium conversion, (-)
AH Standard heat of reaction, J/kmol
ATad Adiabatic temperature rise, K
a, p, y, 6,6 See equation 13
eb Bed voidage, (-)
\i Gas-phase viscosity, Pa-s
t| In A - n
TI E/RgTo
a Ratio of O2 in feed to CH4 in feed, (-)
pg Gas-phase density, kg/m3
ps Solid-phase density, kg/m3
pc Catalyst density, kg/m3
pi Inert solid-phase density, kg/m3
A-13
-------
A-14
-------
APPENDIX B
INDUSTRY CONTACTS
B-1
-------
Appendix B. Industry Contacts
The following firms and individuals supplied information for this report and may be contacted for
further details:
CANMET, Varennes, Quebec, Canada
Hristo Sapoundjiev Research Scientist 450 652-5789
email: hsapound@nrcan.gc.ca
Neill & Gunter, Dartmouth, Nova Scotia, Canada
Brian King Senior Consultant 902 434-7331
email: bking@ngns.com
David Traves Vice President 902 434-7331
email: dtraves@ngns.com
MEGTEC Systems, Goteborg, Sweden
Martin Key Marketing Manager 46 31 6657800
email: mkey@megtec.com
Chalmers University, Goteborg, Sweden
Bjom Heed Assoc. Professor 46 31 7721426
email: heed@entek.chalmers.se
BMP, NSW, Australia
Gary Foulds Prin. Research Engr. email: foulds.gary.ga@bhp.com.au
Bray Solutions Pty Ltd., Oyster Bay, NSW, Australia
Geoff Bray Principal 0295287618
email: braysolutions@ozemail.com.au
Geoff Rigby Principal email: rigby@mail.com
Northwest Fuel Development
Peet Soot President 503 699 9836
email: peetm@teleport.com
Solar Turbines, San Diego, CA
Mohan Sood Engineer 619644-5508
Caterpillar, Lafayette, IN
Len Lloyd Sr. Prod. Consult. 309 578 3201
B-2
-------
Natsource, New York, NY
Hillary Nussbaum Broker
Garth Edward
Broker
Cantor Fitzgerald, New York, NY
Jason Boseck Broker
Carlton Bartels
Broker
TransAlta, Calgary, Alberta, Canada
Paul Vickers Offsets Trader
212232-5305
email: hnussbaum@natsource.com
212232-5305
email: gedward@natsource.com
212938-4250
email: jboseck@cantor.com
212938-4250
email: cbartels@cantor.com
403 267-2033
email: paul_vickers@transalta.com
B-3
-------
B-4
-------
APPENDIX C
SAMPLING OF GAS TURBINE MODELS
C-1
-------
Appendix C. Sampling of Gas Turbine Models
The following list of commercial combustion turbine products includes both new and old models.
The authors have not examined the suitability of any models for a ventilation air project. The list
is offered merely to present a sample of the variety of models that are available. This list is
arranged according to nominally rated output in megawatts.
Source: EPRI (in Power Engineering, March 1999); Solar Turbines; and personal
communications.
<10MW
1.4 MW Heron H-1
1.5 MW Dresser-Rand
1.6+MW OPRAOP-16R
2.0+ MW P&W ST18 Upgrade
2.5+ MW Orendo OGT 2500R
2.6 MW Aviadvigatel GTU-2.5P
2.7+ MW Nuovo Pigone PGT-2 1C
3.4 MW Solar Centaur 40
3.5 MW P&WST30
3.6 MW EGT Typhoon
3.8 MW Allied Signal ASE SO
4.2 MW Solar Mercury 50 ATS
4.7 MW EGT Typhoon
4.8 MW Solar Taurus 60
5.2+ MW Allison 501-KB7
5.3 MW MANGHH THM1203
5.3 MW EGT Typhoon
6.5 MW Sulzer Escher Wyss S3
6.7 MW Allison 601-KB9
7.0 MW Kawasaki M7A-01
8.2 MW Allison 601-KB11
8.9 MW MANGHH THM1304-9
9.0 MW Solar Mars 90
9.8 MW Allied Signal ASE 120
11-20MW
11.0 MW
11.1 MW
11.2 MW
12.0 MW
12.9 MW
13.2 MW
13.4 MW
13.5 MW
15.0 MW
17.9 MW
19.8 MW
Sulzer Escher Wyss S7
CHAT-KM7
Nuovo Pignone PGT 10B
ICAD 2-shaft
EGT Cyclone
Solar Titan
GE LM1600PA
Allison 701 -K
ICAD 3-shaft
Solar ATS "L"
Northrop WR-21
C-2
-------
APPENDIX D
TYPICAL SPREAD-SHEET MODEL FOR ALLOCATION OF GOB GAS
D-1
-------
Appendix D. Typical Spread-Sheet Model for Allocation of Gob Gas
ALLOCATION OF GOB GAS: REACTOR versus TURBINE
0.5% Concentration by Volume
Case 6. 20% Gob Gas to Reactor
Assumptions
Vent air flow
Methane content
Methane heat value
Gob gas flow (methane)
Percent gob gas to reactor
Turbine compressor exit temperature
Reactor exit temperature
Turbine rotor inlet design temperature
212,000 cfm
0.5%
1000Btu/cuft
868 cfm
20%
572 °F
1300°F
1832 °F
CALCULATE HEAT FROM REACTOR
Vent air flow (0.5% methane)
Air flow
Methane flow
Gob gas flow to reactor
Total methane flow to reactor
Total heat to reactor
Methane concentration
Recovery rate (from Figure 6)
Heat recovered from reactor
Mass flow through reactor
Heat to power turbine
212,000 cfm
210,940 cfm
1060 cfm
174 cfm
1234 cfm
1,465,364 Btu/min
0.58 %
82.5 %
1,208,925 Btu/min
72.54 mmBtu/hr
6,916 Ib/min
115.27lb/sec
2,157,840 Btu/min
129.47 mmBtu/hr
CALCULATE POWER GENERATED FROM TURBINE
Heat from reactor
Heat from gob gas
Total heat to power turbine
Total mass to turbine
Temp inlet to turbine rotor
Degrees below turbine rotor inlet design temperature
Turbine efficiency (from Figure 8)
Turbine Output
2,157,840 Btu/min
694,400 Btu/min
2,852,240 Btu/min
171.13 mmBtu/hr
6946 Ib/min
1711°F
121°F
29.1 %
14,591 kW (e)
D-2
-------
ALLOCATION OF GOB GAS: REACTOR versus TURBINE
0.5% Concentration by Volume
SUMMARY OF CASES
Table 1. Heat to Turbine
% Gob Gas to Reactor
% Gob Gas to Turbine
% Heat Recovered
Total Heat Recovered - mmBtu/hr
Total Heat to Turbine - mmBtu/hr
Case 1
0%
0%
80%
62.11
110.67
Table 2. Electrical Power from Turbine
Total Heat from Reactor -
mmBtu/hr
Heat from Gob Gas - mmBtu/hr
Total Heat to Turbine - mmBtu/hr
Temperature at Turbine - °F
Turbine Efficiency - %
Power Produced - kW(e)
Casel
110.67
0.00
110.67
1300
20.0%
6,485
Case 2
100%
0%
89%
115.33
205.86
Case 2
205.86
0.00
205.86
1300
20.0%
12,063
Case 3
75%
25%
87.50%
102.00
182.05
Case 3
182.05
13.02
195.07
1392
22.2%
12,689
Case 4
50%
50%
85.70%
88.74
158.39
Case 4
158.39
26.04
184.43
1510
24.8%
13,402
CaseS
25%
75%
83.30%
75.41
134.60
Case 5
134.60
39.06
173.66
1671
28.4%
14,450
CaseG
20%
80%
82.50%
72.54
129.47
CaseG
129.47
41.66
171.13
1711
29.1%
14,591
Case?
15%
85%
82%
69.96
124.87
Case 7
124.87
44.27
169.14
1753
29.6%
14,669
CaseS
10%
90%
81.50%
67.41
120.32
CaseS
120.32
46.87
167.20
1797
29.9%
14,623
Case
0%
100%
80%
62.00
9
110.67
Case 9
110.67
52.08
162.75
1900
30.0%
14,306
D-3
-------
D-4
-------
APPENDIX E
ILLUSTRATIVE ECONOMIC MODELS
E-1
-------
Appendix E. Illustrative Economic Models
E -1: Comparison of a 125 MW Mine-Mouth Coal Plant with a Traditionally Sited 125 MW
Plant (Page 1 of 1)
DISCOUNTED CASH FLOW ANALYSIS
Year
Cash Row: incremental invest-
ment and annual savings.
Simple IRR 30.29%
(SOOO'l)
0123
16.813 -5.481 -5.481 -5.481
-5.481
-5.481
6
-5.481
7
-5.481
8
-5,481
9
•5.481
Mine Data mmcfd
Vent methane flow 2.00
Vent methane concentration 0.005
Vent air flow 400
Gob gas available 2.00
Mine-Mouth Coal Plant Assumptions
Capacity -kW 125.000
Heat rate - Btu/kWh 10.000
Length TM line - miles 30
NOx emission - Ib/mmBtu 0.45
NOx reduction - per % methane 5%
Availability - hr/yr 7.446
CH4 destroyed - Mt/h 3.21
CO2 equivalent - Mt/h 67.43
Capital Cost Assumptions
Trad coal plant cap cost S/kW 1.400
Labor % of plant cost 0.4
Remote labor, premium 0.15
Remote plant labor adder S/kW 84
TM cost S/mile 200.000
TM line adder S/kW 48
Dry tower cost S/kW 2.5
Mine mouth addl cap cost SAW 1 34.50
Mine Mouth extra capital cost 16.813
Operating Cost Assumptions
Annual production mmkWh/yr 930.75
NOx cost Won 2000
Dry tower derate: % of 3 cents 2%
Norn cost baseline power S/kWh 0.03
mcMi
83.3;
83.33
Mine Mouth Fuel Mix Fraction
Vent methane 0.067
Gob gas 0.067
Coal 0.867
Mine Mouth Unit Fuel Cost S/mmS/u
Coal cost 1 .4C
Coal freight cost 014
Net coal cost 1 .26
Gob gas cost 0.60
Vent methane cost 0.00
Fuel Cost per kWh SftWh
Trad. Plant-Coal 100% 0.01'
MM Plant - Coal tract. 0.0109:
MM Plant.VA methane 0
MM Plant - Gob gas 0.000*
MM Plant - composite 0.01 1 3i
NOx Credits
Ib's NOx emitted/kWh 0.004!
MM Plant reduc. tract. 0.6667
MM Plant red. Lb/KWh 0.00:
NOx red Value/kWh 0.00:
Dry Tower Derate S/kWh
Cnst ner kWh -O.OOOf
Total Oper Cost Changes VttWh
Fuel cost savings 0 00261
NOx credit 0.00:
Dry tower derate -O.OOW
CO2 credit _OJffiQa2S
Total 0.00588'
Carbon Credits
CO2 reduction Ml/kWh 0.00053!
CO2 credit value S/Mf 1 .5C
CO2 credit /kWh S/kWh 0.00080!
Sensitivity: (base case bold)
TM line miles IRR
10 4145*
20 SS.ig*
30 90.29%
40 26 32*
Gob gas mmcfd
1.00 2275%
2.00 30.29*
3 00 37 47*
Derate %
0 3400
-------
E-2:
Electricity Generation Using Either TFRR or CFRR (Page 1 of 3)
Mine Data
Vent air flow
CH4 concentration
Vent air methane
Gob gas available
Gob gas to reactor
Gob gas to turbine
Operating Assumptions
Enhanced concentration
Fuel => reactor
Reactor heat recovery %
Reactor heat rec =>GT
Total heat =>GT if fired
Air mass thru heat exch
Gross elec potential unfired
Gross elec potential fired
Booster fan power draw
Wise parasitic power draw
Electric capacity purchased
Elec cap net
Thermal capacity
Operating hours/year
Thermal market hours/year
Electricity sold/year
Heat sold/year
Methane destroyed
CO2 equiv destroyed
Total CO2 mitigated
Revenue and Cost Assumptions
Thermal price
Elect price
Carbon credit
Gob gas fuel
Gob gas fuel
TG maint
Misc oper & OH cost
Reactor capital cost
Power plant cap cost
Installed cap cost
Project "soft" costs
Total capital cost
Financial Assumptions
Project term - years
Loan-% of capital cost
Interest rate
Loan term - years
Escalation - %/year
0.005
mmcfd |
305
1 53
1 25
050
0.75
mcf/h
12.708
fired
6354
5208
20.83
31.25
mj/s
100
0.50
041
0.16
0.25
mmcfd |
305
1 53
060
060
0.00
mcf/h |
12,708
unfired
63.54
2500
2500
0
mj/s
100
050
020
020
0
kg/s
kW(e)
kW(e)
kW(e)
kW(e)
kW(e)
kW(e)
kW(t)
90%
75%
mmkWh(e)
mmkWh(t)
Mt/h
Mt/h
Mt/y
$/kWh(t)
$/kWh(e)
$/Mt
$/mmBtu
$/yr
$/kWh
$000/yr
$000/proj
$000/proj
$000/proj
%
$000/proj
12
70%
10%
8
2.5%
%
0.0066
0.785
001
0.035
1 50
060
00035
25%
Loan amt
mmBtu/h
84.38
6621
9746
53 11
7,996
650
450
7,996
6,896
10.896
7,884
6,570
5437
71.59
2.227
46.78
368,792
246
267
3,150
5.197
8,347
10.434
7,304
Gj/h
8895
69.80
10274
%
0.0070
0808
mmBtu/h
88.54
Gj/h
9334
71 52 75 39
-. - ^'SB^mnKMMnH
-"•^•IBHHMHaBn
5574]
4,610
650
450
5,993
3,510
11,434
7.884
6.570
2767
75.12
1.706
35.82
282.408
118
225
3,150
3,895
7,045
8,807
6.165
E-3
-------
E - 2: Electricity Generation Using Either TFRR or CFRR (Page 2 of 3)
Cash Flow Anarytls-unflred
Year
REVENUES
Electric
Thermal
Carbon credits
Total Revenue
COSTS
04 M Costs
Fuel cost • gob gas
Interest
Depredation
Total Cost
Income Before Tax
Fed/State income tax
AFTER TAX INCOME
CASH FLOW ADJUSTMENT
Depredation
Principal Payback
CASH FLOW
CASE IRR
Loan Coverage
Decree 150%. 0.5 yr. 7.5yr
0
38%_
-2.642
20.2%
1
969
751
424
2.143
-322
•118
-616
-705
-1,762
382
-145
237
705
-539
402
1 45
0.1000
2
993
770
434
2.197
-330
-121
-563
-1.268
-2.282
-85
32
-53
1.268
-593
622
1.64
0.1800
3
1.018
789
445
2.252
-339
-124
-503
•1.015
-1.981
271
-103
168
1.015
-652
530
1 57
01440
4
1.043
809
456
2,308
-347
-127
-438
-812
-1,724
584
-222
362
812
-717
456
1 51
0.1152
5
1.069
829
468
2.366
•356
-131
-366
•812
-1.664
702
-267
435
812
-789
457
1.51
0.1152
6
1.096
850
479
2.425
-365
-134
-287
-812
-1.597
828
-314
513
812
-868
457
1.51
0.1152
7
1.123
871
491
2.486
-374
•137
-201
-812
-1.523
963
-366
597
612
-955
453
1.51
0 1152
8
1.151
693
504
2.548
-383
-141
-105
-812
-1.440
1.107
-421
687
812
-1.050
448
1 51
0 1152
9
1.180
915
516
2.611
-393
-144
-537
2.075
•788
1.286
1.286
10
1.210
938
529
2,677
-403
-148
-550
2.127
-808
1.318
1.318
11
1.240
962
542
2,744
-413
-151
-564
2,180
-828
1,351
1.351
12
1,271
986
556
2.812
•423
-155
-578
2.234
-849
1,385
1,385
E-4
-------
E - 2: Electricity Generation Using Either TFRR or CFRR (Page 3 of 3)
Cash Flow Analysis-fired
Year
REVENUES
Electric
Thermal
Carbon credits
Total Revenue
COSTS
04 M Costs
Fuel cost - gob gas
Interest
Depreciation
Total Cost
Income Before Tax
Fed/Slate income lax
AFTER TAX INCOME
CASH FLOW ADJUSTMENT
Depreciation
Principal Payback
CASH FLOW
CASE IRR
Loan Coverage
0
38%
-3,130
293%
1
1.903
716
553
3.172
-457
-246
-730
-835
-2.269
903
-343
560
835
-639
756
1 73
2
1.950
734
567
3.251
-469
•253
-667
-1.503
-2.890
361
-137
224
1.503
-703
1.024
1 93
3
1.999
752
581
3.332
-481
-259
-596
-1,202
-2,538
795
-302
493
1.202
-773
922
1 86
4
2.049
771
596
3,416
•493
-265
-519
-962
-2.238
1,177
-447
730
962
-850
841
1 81
5
2.100
790
611
3.501
-505
-272
-434
-962
-2.172
1.329
-505
824
962
-935
850
1 82
6
2.153
810
626
3.589
•518
-279
-340
-962
-2.098
1.490
-566
924
962
-1.029
857
1 83
7
2.207
830
642
3.678
-530
-286
-238
-962
-2.015
1.663
-632
1.031
962
-1.131
861
1 84
8
2,262
851
658
3.770
-544
-293
-124
•962
-1.923
1.848
-702
1.146
962
-1.245
863
1 84
9
2.318
872
674
3.865
•557
•300
-857
3.007
-1.143
1.864
1.864
10
2.376
894
691
3.961
-571
•308
-879
3.082
•1.171
1 911
1.911
11
2.436
916
708
4.060
-586
-315
-901
3.159
-1.201
1.959
1.959
12
2.497
939
726
4.162
-600
-323
•923
3.238
-1.231
2.008
2.008
E-5
-------
E - 3: Steam Generation Only with Either TFRR or CFRR (Page 1 of 2)
Mine Data
Vent air flow
CH4 concentration
Vent air methane
Gob gas available
Operating Assumptions
Enhanced concentration
Fuel => reactor
Reactor heat recovery %
Reactor heat rec =>boiler
Booster fan power draw
Misc parasitic power draw
Air mass thru heat exch
Thermal output
Thermal market hours/year
0.005
0.0075
0.845
kW(e)
kW(e)
kg/s
kW(t)
90%
mmcfd
305
1.53
0.76
mmBtu/h
95.31
80.54
650
250
117.60
18.878
7884
mcf/h
12,708
63.54
31.77
Gj/h
100.48
84.90
100
0.50
0.25
Heat sold/year
Methane destroyed
CO2 equiv destroyed
Total CO2 mitigated
Revenue and Cost Assumptions
Thermal price
Carbon credit
Gob gas fuel
Gob gas fuel
Power cost
Misc oper & OH cost
Reactor capital cost
Waste heat boiler complete
Installed cap cost
Project "soft" costs
Total capital cost
Financial Assumptions
Project term - years
Loan-% of capital cost
Interest rate
Loan term - years
Escalation - %/year
mmkWh(t)
Mt/h
Mt/h
Mt/y
12
70%
10%
8
2.5%
148.84
1.836
38.56
304,004
$/kWh(t)
$/Mt
S/mmBtu
$/yr
$/kWh
$000/yr
SOOO/proj
$000/proj
SOOO/proj
%
SOOO/proj
0.010
1.50
0.60
150
0.05
131
3.150
944
4.094
25%
5.117
Loan amt
3,582
E-6
-------
E- 3: Steam Generation Only with Either TFRR or CFRR (Page 2 of 2)
Cash Row Analysis
Year
REvBJUES
Thermal
Carbon oedts
Total Revenue
COSTS
O&MCDsts
Interest
Depredation
Total Cost
Income Before Tax
FeoYState income tax
AFTBnAXINCCWE
CASH FLOW AQWSTOBfl-
Depredation
Rindpal Payback
CASHFLOW
CASEIRR
Loan Coverage
Deprec150%l.5>7.5yr
0
38%
-1,535
33.3%
1
1,488
456
1,944
-636
-358
409
-1,404
541
-205
335
409
-313
431
1.64
0.1000
2
1,526
467
1,993
-652
-327
-737
-1,716
277
-105
172
737
-345
564
1.84
0.1800
3
1,564
479
2,043
•668
-292
-590
-1,550
493
-187
305
590
-379
516
1.77
0.1440
4
1,603
491
2,094
-685
-255
-472
-1,411
683
-259
423
472
-417
478
1.71
0.1152
5
1,643
503
2,146
-702
-213
•472
-1,387
760
-289
471
472
459
484
1.72
0.1152
6
1,684
516
£200
-720
-167
472
-1,358
842
-320
522
472
-504
489
1.73
0.1152
7
1,726
529
P255
-738
-117
472
-1,326
929
-353
576
472
-555
493
1.73
0.1152
8
1,769
542
2,311
-756
-61
472
-1.289
1,022
-389
634
472
-610
495
1.74
0.1152
9
1,813
556
2,369
-775
-775
1,594
•606
968
988
10
1,859
569
2,428
-794
-794
1,634
-621
1,013
1,013
11
1,905
584
2,489
-814
-814
1,675
-636
1,038
1,038
12
1,953
598
2,551
-835
-835
1,717
-652
1,064
1,064
E-7
-------
E-8
-------
APPENDIX F
CO2 EMISSION TRADING
F-1
-------
Appendix F. CO2 Emission Trading
Opportunities are developing to enhance profitability of alternative energy projects by usinq
greenhouse gas (GHG) credits trading. Because methane has approximately 21 times the
global warming effect of carbon dioxide on the basis of weight, projects that capture and destroy
methane in mine ventilation air have the potential for significant reduction of GHG emissions
CO2 emission reductions result from destroying, while beneficially using, the methane contained
in ventilation air instead of allowing it to be released into the atmosphere. The great global
warming potential of coal mine methane makes ventilation air capture projects valuable in terms
of GHG credits. A project developer may be able increase profits by selling to a third party
greenhouse gas credits from a project that captures and destroys ventilation air employing
either ancillary or primary use technology.
While the criteria governing a national and international greenhouse gas emissions market have
not been formalized, market activity has begun. At present a purchaser's lowest-cost route is
through the purchase of early reduction credits on the open market through one of several
brokerage firms specializing in emissions transactions.1 Early reduction credits are beginning to
be traded and may be banked by the purchaser or transferred to a third party at a later date.
Project developers may also be interested in an ongoing request for proposals (RFP) for GHG
mitigation projects from TransAlta, a Canadian energy company. The company's Web site
invites participants such as businesses, nongovernmental organizations, business associations,
and government agencies, as well as academic and research institutions, to submit project
proposals for TransAlta's 1998 GHG offset RFP in accordance with the guidelines in the
proposal outline section.2 The company prefers projects that mitigate over 250,000 metric
tonnes of CO2 annually.
The few trades known to have been completed are within the $1-3 range per metric tonne of
CO2. The following are descriptions of a few emission trades that were undertaken between
1998 and 1999.
• Ontario Hydro agreed to purchase GHG emission credits earned by a methane-powered
generator to be built by Toromont Energy, Ltd. Ontario Hydro is buying credit for
290,000 metric tonnes of CO2 equivalent from the 3.5 MW plant that flares methane gas.
Ontario Hydro is also expected to receive credit for another 157,000 metric tonnes per
year of CO2 equivalent from the 3.5 MW plant, which will burn roughly 700 million cubic
feet/year of methane gas to produce power. The price of the trade was undisclosed, but
1 Two brokerage firms made presentations at the U.S.EPA Workshop on International Coal Mine
Methane Business Opportunities: Projects. Services. Technologies, and Financing, on May 6,1999 at
the University of Alabama, Tuscaloosa, AL. For quotes or further details contact either Mr. Jason
Bosek at Cantor Fitzgerald (212 938-4250) or Ms. Hillary Nussbaum at Natsource (212 232-5353).
2 TransAlta's RFP appears on its website - www.transalta.com, on the community & environment page in
the sustainable development section. Contact information is as follows: phone - 403 267-4746, fax -
403 267-7372, email - sustainable_development@transalta.com, address - TransAlta, Sustainable
Development, Box 1900, Station "M", 110 - 12th Avenue SW, Calgary, Alberta T2P2M1 Canada.
F-2
-------
an Ontario Hydro spokesperson was quoted in a trade newsletter, Air Daily, as saying,
as a point of reference, that $1-2 is a "very reasonable" price (December 8, 1998).
• Niagara Mohawk Power Corporation and Arizona Public Service Company swapped
1.75 million metric tonnes of CO2 reductions for 25,000 metric tonnes of SO2 in 1994.
According to NATSOURCE, Inc., an over-the-counter broker of energy products, the
implied CO2 price, based on the SO2 market value at the time of the swap, was $2.11
per metric tonne of CO2 equivalent.
• In one of the first international emission trades, Suncor agreed to purchase 100,000
metric tonnes of CO2 from Niagara Mohawk Power Corporation in March 1998. Carbon
emissions reductions will occur as Niagara Mohawk switches from coal to natural gas,
undertakes renewable energy projects, and promotes the efficient use of energy by its
customers. Suncor also has an option to purchase an additional 10 million metric tonnes
of greenhouse gas reductions for up to $6 million from Niagara Mohawk after the year
2000.
• In October 1999 the Chicago-based brokerage firm, Environmental Financial Products,
LLC, arranged a transaction for GHG emission reduction credits between Ontario Power
Generation, Inc. of Canada and U.S.-based Zahren Alternative Power Corporation. The
price for the equivalent of 2.5 million metric tonnes of CO2 was not disclosed. The
Zahren-generated credits, starting in 1998 and ending in 2000, result from combusting
landfill methane to produce electric power at its landfill gas-to-energy projects at 20 U.S.
locations. Ontario's Pilot Emission Reduction Trading Program will review the trade, and
the emission reductions will be reviewed by PricewaterhouseCoopers, LLP
Vs this report goes to press, both Mr. Bosek and Ms. Nussbaum (see footnote 1) observe that
>oth buyers and sellers of greenhouse gas emissions credits feel comfortable with the CO2 price
n the $1.50 per metric tonne range for qualified projects. They both believe that this price will
icrease as more players enter the market.
F-3
------- |