vvEPA
United States
Environmental Protection
Agency
Air And
Radiation
(ANR-445)
EPA/400/9-90/008
September 1990
Methane Emissions
From Coal Mining
Issues And Opportunities
For Reduction
Vent Stack
Electric
Blower
Pre-Drilled
Gob Well
Printed on Recycled Paper
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Methane Emissions
From Coal Mining:
Issues and Opportunities
for Reduction
Prepared By:
C.M. Boyer II
J.R. Kelafant
V.A. Kuuskraa
K.C. Manger
ICF Resources Incorporated
Dina Kruger
U.S. Environmental Protection Agency
September 1990
-------
Table Of Contents
List of Exhibits ii
Overview and Introduction 1
Key Findings 2
Report Organization 5
I. Methane Generation, Storage, and Flow in Coal 7
Coal Formation 7
Methane Generation and Storage 11
Methane Flow 12
Measuring the Methane Content of Coal 17
II. Methane Emissions During Coal Mining 19
Methane Emissions During Coal Mining 19
Methane Emission Control Measures 25
Post-Mining Emissions 31
III. Methane Emissions Estimate For Global Coal Mining 35
Methane Emissions from United States Coal Mines 36
Methane Emissions from Foreign Coal Producing Countries 49
Global Estimates of Methane Emissions from Coal Mining 53
Study Uncertainties 58
IV. Technical and Economic Evaluation of Methane Control Techniques 61
Options for Methane Utilization 61
Economic Evaluation of Methane Control Techniques 64
Preliminary Economic Analysis Findings and Results 76
List Of References Cited 83
Appendix A A-1
Appendix B B-1
Appendix C C-1
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List of Exhibits
Page
Exhibit 1 -1 - Stages in the Coalification Process 8
Exhibit 1 -2 - Approximate Values of Some Coal Properties
in Different Rank Ranges 10
Exhibit 1 -3 - Gas Quantities Generated During Coalification 11
Exhibit 1 -4 - Methane Generation and Adsorptive Capacity 12
Exhibit 1 -5 - Relationship Between Adsorbed Methane Volumes and Depth
and Pressure for Different Coal Ranks 14
Exhibit 1 -6 - The Transport of Methane Gas in Coal 15
Exhibit 1 -7 - Schematic Illustration of the Coal Cleat System (Plan View) 16
Exhibit 2-1 - Representative Stratigraphic Columns for
Four Coal Basins of the World 20
Exhibit 2-2 - Schematic Diagram of the Development of a Room and Pillar Mine 22
Exhibit 2-3 - Schematic Diagram of Longwall Mine Development 24
Exhibit 2-4 - Schematic Diagram of Horizontal and Cross-Measure Boreholes 28
Exhibit 2-5 - Schematic Diagram of a Gob Well 29
Exhibit 2-6 - Gas and Water Production Curves for a Typical Vertical Well 31
Exhibit 3-1 - Underground, Surface, and Total Coal Production
in the United States, 1987 35
Exhibit 3-2 - Major U.S. Coal Basins and Coalbed Methane Resources 38
Exhibit 3-3 - Relationship Between Gas Content and Depth
Central Appalachian Basin 39
Exhibit 3-4 - Average Methane Content in Mined Coal 41
Exhibit 3-5 - Methane Emissions vs. In-Situ Methane Content -
Selected U.S. Coal Mines 42
Exhibit 3-6 - Methane Emissions vs. In-Situ Methane Content -
59 U.S. Coal Mines 44
Exhibit 3-7 - Estimated Methane Emissions from U.S. Coal Mining and Utilization
by State, 1987 48
Exhibit 3-8 - Estimated Methane Emissions from U.S. Coal Mining and Utilization
by Mining Method and Source 49
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List of Exhibits
Page
Exhibit 3-9 - Underground, Surface, and Total Coal Production in the
Ten Primary Foreign Coal Producing Countries, 1987 51
Exhibit 3-10 - Estimated World Methane Emissions From Coal Mining 52
Exhibit 3-11 - Estimated Global Future Methane Emissions From Coal Mining
and Utilization 55
Exhibit 3-12 - Comparison of Coal Mining-Related Emission Estimates 56
Exhibit 4-1 - Summary Coal and Gas Properties for Production Modeling
Warrior Coal Basin 66
Exhibit 4-2 - Summary Coal and Gas Properties for Production Modeling
Northern Appalachian Coal Basin 68
Exhibit 4-3 - Capital and Operating Costs Vertical Wells in Advance of Mining 71
Exhibit 4-4 - Capital and Operating Costs In-Mine Horizontal Boreholes
in Advance of Mining 72
Exhibit 4-5 - Capital and Operating Costs Vertical Gob Wells During Mining 73
Exhibit 4-6 - Economic Analysis of Three Degasification Systems in the
Warrior Basin 78
Exhibit 4-7 - Economic Analysis of Three Degasification Systems in the
Northern Appalachian Basin 79
Exhibit C-1 - Summary of Coalbed Methane Production Pre-Drainage Using
Vertical Wells Completed in All Coal Seams, Warrior Basin C-2
Exhibit C-2 - Economic Benefits of Using Vertical Wells for Methane
Recovery in the Warrior Basin C-3
Exhibit C-3 - Economic Benefits of Using Vertical Wells for Methane
Recovery in the Warrior Basin C-5
Exhibit C-4 - Summary of Coalbed Methane Production Drainage Using
Vertical Gob Wells During Mining, Warrior Basin C-6
Exhibit C-5 - Economic Benefits of Using Gob Wells for Methane
Recovery in the Warrior Basin C-7
Exhibit C-6 - Summary of Coalbed Methane Production Pre-Drainage Using
In-Mine Horizontal Boreholes Completed in the
Mary Lee Coal Seam, Warrior Basin C-8
in
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List of Exhibits
Exhibit C-7 - Economic Benefits of Using Horizontal Boreholes for
Methane Recovery in the Warrior Basin C-9
Exhibit C-8 - Summary of Coalbed Methane Production Pre-Drainage Using
Vertical Wells Completed in the Mary Lee Coal Seam
and Drainage Using Vertical Gob Wells During Mining,
Warrior Basin C-11
Exhibit C-9 - Economic Benefits of Using Vertical and Gob Wells for
Methane Recovery in the Warrior Basin C-12
Exhibit C-10 - Summary of Coalbed Methane Production Pre-Drainage Using
Vertical Wells Completed in all Coal Seams,
Northern Appalachian Basin C-14
Exhibit C-11 - Economic Benefits of Using Vertical Wells for
Methane Recovery in the Northern Appalachian Basin C-15
Exhibit C-12 - Economic Benefits of Using Vertical Wells for
Methane Recovery in the Northern Appalachian Basin C-16
Exhibit C-13 - Summary of Coalbed Methane Production Drainage Using Vertical
Gob Wells During Mining, Northern Appalachian Basin C-17
Exhibit C-14 - Economic Benefits of Using Gob Wells for
Methane Recovery in the Northern Appalachian Basin C-18
Exhibit C-15 - Summary of Coalbed Methane Production Pre-Drainage Using
In-Mine Horizontal Boreholes Completed in the
Pittsburgh Coal Seam, Northern Appalachian Basin C-20
Exhibit C-16 - Economic Benefits of Using Horizontal Boreholes for
Methane Recovery in the Northern Appalachian Basin C-21
Exhibit C-17 - Summary of Coalbed Methane Production Pre-Drainage Using
Vertical Wells Completed in the Pittsburgh Coal Seam and
Drainage Using Vertical Gob Wells During Mining,
Northern Appalachian Basin C-22
Exhibit C-18 - Economic Benefits of Using Vertical and Gob Wells for
Methane Recovery in the Northern Appalachian Basin C-23
IV
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OVERVIEW AND INTRODUCTION
In recent years, methane (CH4) has been identified as a potent greenhouse gas with a
radiative forcing potential of 30 to 55 times that of carbon dioxide per kilogram emitted.1 Total
annual methane emissions from all sources are estimated to be about 540 (ą95) teragrams and
anthropogenic sources account for 65 to 70 percent of total emissions.2'3 It has been
documented that atmospheric concentrations of methane have more than doubled over the last
two centuries and are continuing to increase on the order of 1 percent annually, or about 0.017
ppmv (parts per million by volume) per year.
Increasing atmospheric concentrations of methane will have important implications for
global climate and perhaps for the stratospheric ozone layer and background levels of
tropospheric ozone. Thus, the U.S. Environmental Protection Agency has initiated a series of
studies to more completely understand the various sources of emissions, to develop
methodologies for estimating emissions from these sources, and to explore the technologies and
economics of reducing methane emissions. Based on these studies, strategies for stabilizing and
further reducing methane emissions will be developed.
Coal mining, particularly from underground mines, contributes to the increasing
abundance of atmospheric methane, accounting for 7 to 12 percent of annual methane emissions
(33 to 64 million metric tons in 1987). Coal production has been increasing steadily in the last
30 years and in 1987 world coal production reached 4.6 billion metric tons. With world energy
demand still growing, coal production levels are expected to continue to increase in the future.
Thus, methane emissions from this source could increase significantly, perhaps reaching 72 to
81 million metric tons by the year 2000 if options for reducing emissions are not pursued.
1 The ratio of carbon dioxide to methane depends on how long into the future the radiative effects are
compared since methane has a much shorter lifetime in the atmosphere than CO2. These ratios represent the
relative effects over the next 50 to 100 years.
2 One million metric tons (1012 grams or 1 teragram) is equal to 1.49 billion cubic meters (52.6 billion cubic
feet).
3 R.S. Cicerone and R.S. Oremland, 1988.
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Methane is generated during the process of coal formation and is subsequently stored
in the coal seams and surrounding rock strata. Methane is contained in the coal and other strata
by pressure, and when pressure decreases (either naturally through uplift and erosion or as a
result of mining activities) methane flows out of the coal and into the atmosphere. Methane
released as a result of underground mining activities flows first into the mine workings, where it
is a safety hazard because it is explosive in low concentrations in air. As a result, underground
mines are ventilated with large quantities of air to remove the methane and vent it to the
atmosphere.
A number of technologies have been developed to degasify coal seams and reduce
methane emissions into mine workings. To a large extent, these technologies have been used
for purposes of mine safety and to reduce the operating costs of the mines. For the most part,
methane recovered using these technologies is currently vented to the atmosphere. However,
more of this methane could be recovered and utilized without compromising mine safety.
Reducing methane emissions from coal mining by recovering and using this liberated gas
could play a key role in stabilizing the atmospheric methane concentrations at approximately
present levels. Currently, opportunities to recover methane from coal mining are limited by a
variety of technical, legal, regulatory, institutional and other barriers. These barriers must be
identified and removed if the recovery of methane liberated during coal mining is to be widely
pursued.
Key Findings
This report estimates global methane emissions from coal mining on a country-specific
basis, evaluates the technologies available to degasify coal seams, and assesses the economics
of recovering methane liberated during mining. The draft findings of this report were presented
at the "International Workshop on Methane Emissions from Natural Gas Systems, Coal Mining
and Waste Management Systems," which was held in Washington, D.C., on April 9 to 13, 1990.
These findings were discussed during the workshop and revised based on the comments
received during the discussions. The findings of the workshop regarding methane emissions
-------
from coal mining and a list of the workshop attendees for this session are included in
Appendices A and B of this report.
The report's main findings are presented below. Based on this analysis and the
consensus of the recent international workshop, it appears that there are promising opportunities
for reducing methane emissions from coal mining. Some of these opportunities have been
demonstrated, and others remain to be assessed and demonstrated in the field. Undertaking the
necessary technical assessments and demonstrations is a recognized priority.
Emission Estimates
The study estimates that 33 to 64 million metric tons of methane were liberated in 1987
as a result of coal mining, processing and utilization. More than 90 percent of these
emissions were associated with coal mining activities in the top ten coal producing
nations, and almost 75 percent were associated with coal production in only four
countries (China, the Soviet Union, Poland, and the United States).
Methane emissions associated with coal mining are likely to increase in the future and
could reach 72 to 81 million metric tons by the year 2000. These increases will be driven
by increased world coal production and by the expected shift in many countries toward
deeper underground coal mines as more accessible, shallower coal seams are
exhausted.
The estimates contained herein are based on numerous assumptions and should be
considered preliminary and approximate. In this study, methane emissions were divided
between those from surface and underground mines, which represent a major source of
variation in emission levels. Other sources of uncertainty and variation remain, however,
including the relationship between in-situ methane content in the coal and methane
emissions during mining and the extrapolation of U.S. estimates to other countries. A
range of ą23 percent was assumed for U.S. methane emissions from coal mining to
account for the uncertainties associated with estimating mining emissions based on the
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methane content of the mined coal. An additional uncertainty of ą10 percent was
assumed in estimating international methane emissions based on U.S. data.
Methane Recovery and Utilization
Methane is explosive in concentrations of 5 to 15 percent in air, and as a result, control
of methane has long been essential in underground coal mines for safety reasons. Over
the years, a number of techniques have been developed to degasify coal seams and
supplement conventional underground mine ventilation systems. Many of these
techniques are used in underground mines in the United States and other countries.
In many cases, the methane recovered using these degasification techniques is currently
vented to the atmosphere. This methane could be used in a variety of ways, including
on-site power generation, chemical feedstocks, and sale to natural gas pipelines.
Although the economics of methane recovery must be assessed on a site-specific basis,
preliminary economic analyses indicate that under certain conditions methane recovery
is economically attractive. Key factors affecting the economics of methane recovery are:
1) the quantity of methane produced (specific to the unique properties of the coal); 2) the
quality of the recovered methane; 3) the capital and operating costs of degasification
technologies; 4) the selling price of the recovered methane (if injected into natural gas
pipelines or utilized for other purposes); and 5) whether the environmental benefits of
reducing methane emissions are incorporated into the economic analysis.
Opportunities to recover methane prior to or in conjunction with coal mining are also
affected by a variety of other factors, some of which include: 1) the legal ownership of
the coalbed methane; 2) mining regulation constraints; and 3) establishing project
economic viability. Exploring these factors is beyond the scope of this report. Additional
efforts must focus on identifying and removing these and other barriers if the recovery of
methane liberated during coal mining is to be widely pursued.
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Report Organization
This report presents estimated methane emissions from coal mining and summarizes the
issues associated with recovering and utilizing this methane. It is organized into four chapters
as follows:
Chapter I Methane Generation, Storage, and Flow in Coal
Chapter II Methane Emissions During Coal Mining
Chapter III Methane Emissions Estimate for Global Coal Mining
Chapter IV Technical and Economic Evaluation of Methane
Control Techniques
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CHAPTER I
Methane Generation, Storage, and Flow in Coal
The process of coal formation, commonly called coalification, inherently generates
methane and other byproducts. The formation of coal is a complex physio-chemical process
occurring over a period of millions of years. The degree of coalification (coal rank) determines
the quantity of methane generated and, once generated, the amount of methane stored in coal
is controlled by the pressure and temperature of the coal seam and other, less defined
characteristics of the coal.
The methane will remain stored in the coal until the pressure on the coal is reduced,
which can occur through the erosion of overlying strata or because of coal mining. Once the
methane has been released, it flows through the coal toward a pressure sink (such as a coal
mine) and into the atmosphere.
Coal Formation
Coal is a heterogeneous, carbon-rich (>50% by weight) material that is formed by the
biochemical and geochemical alteration of peat, an organic material that is the source of most
of the world's coal deposits. During the progressive transformation of peat into coal, discrete
coal stages (or coal ranks) are attained that are dependent upon specific physio-chemical
conditions, such as 1) heat flow, 2) pressure, 3) hydrogen ion concentration (pH), and 4)
oxidation-reduction (redox) potential. This progressive transformation of organic matter begins
with peat and ends with graphite (or pure carbon), as shown in Exhibit 1-1.
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EXHIBIT 1-1
STAGES IN THE COALIFICATION PROCESS
*
z
DC
O
O
O
1
LU
DC
O
Graphite
t
Anthracite
t
Bituminous
t
Sub-Bituminous
t
Lignite
i
Peat
Prepared by: ICF Resources, 1990.
The coalification process is divided into two stages, an early biochemical stage and a later
a geochemical stage.4 Biochemical coalification begins with the deposition of the peat and
continues through the lignite and sub-bituminous coal ranks. In this first stage, the easily
degradable compounds such as protoplasm, chlorophyll, and cellulose are converted to carbon
dioxide, water, methane, and ammonia by the action of aerobic and anaerobic bacteria. The
gaseous products formed during this stage are emitted to the atmosphere if the peat is not
4 Stach, E., 1975; Van Krevelen, D.W., 1961.
8
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deeply buried, move into overlying sediments if the peat is not capped by an impermeable layer,
or remain in the peat. These biochemical processes occur at low temperatures, less than 50°C,
and require reducing and acidic conditions.
As the altered peat undergoes further burial, increases in temperature and pressure initiate
more complex chemical reactions in the remaining organic material. This is the geochemical
stage of coalification, and it occurs above 50°C. With increasing geochemical alteration, the
hydrogen and oxygen content of the organic material decreases, forming volatile by-products
such as carbon dioxide, water, and methane. This causes a corresponding increase in the
carbon content of the coal and in increased aromatization of the remaining organic compounds.
The chemical components of coals of different rank are shown in Exhibit 1 -2.
Of the two forces that cause geochemical coalification-heat and pressure-heat is the
primary agent. In most cases, the heat source for coalification is supplied by the earth's
geothermal energy, which increases with depth of burial. The geothermal gradient varies from
10°C/km to 50°C/km and averages about 30°C/km.5 During the geologic past, high rank coal
seams may have been covered by 10 kilometers or more of overlying strata, resulting in a burial
temperature of over 300°C.
Although less important than heat, pressure also affects geochemical coalification, often
controlling the temperature at which a specific chemical reaction can take place. As with
temperature, pressure also increases with depth of burial. The average lithostatic gradient of 22.6
kPa/m and the average hydrostatic gradient of 9.79 kPa/m provide a first order estimate for
relating depth to burial pressure.
5 Mason, B., 1966.
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EXHIBIT 1-2
APPROXIMATE VALUES OF SOME COAL PROPERTIES IN DIFFERENT RANK RANGES
Bituminous
%c
%H
%O
Aromatic C Atoms1
(% of total C)
Benzene rings/layer
Volatile matter3, %
Lignite
65-72
4.5
30
50
1-2
40-50
Subbituminous Hiqh Volatile
72-76
5.0
18
65
N/A
35-50
76-87
5.5
4.13
N/A2
2-3
31-45
Medium Volatile
89
4.5
3-4
80-85
2-3
31-20
Low Volatile
90
3.5
3.0
85-90
5
20-10
Anthracite
93
2.5
2.0
90-95
>25
<10
1 Those carbon molecules that are bonded together by ringed structures.
2 Not Available
o
Those substances, other than moisture, that are given off as gas and vapor during combustion.
Source: Crelling, J.C, and Dutcher, R.R., 1988.
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The volatile by-products-primarily carbon dioxide, water, methane and nitrogen-are
generated during biochemical and geochemical coalification. As shown in Exhibit 1 -3, methane
generation increases dramatically as the coal approaches the low volatile bituminous rank.
EXHIBIT 1-3
GAS QUANTITIES GENERATED DURING COALIFICATION
YMd cf/ton
1800 3200
Coal Rank
MOO
Source: Hunt, J.M., 1979.
Methane Generation and Storage
Methane in coal is primarily stored as a monomolecular layer adsorbed onto the internal
coal surface. Significant quantities of methane can be adsorbed in this fashion since the
molecules are tightly packed in the monomolecular layer and because coal has a very large
11
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internal surface area. Pressure (and to a lesser degree temperature) controls the absolute
quantity of methane adsorbed on coal. As pressure increases (and/or temperature decreases),
more methane can be adsorbed in the coal.
As coal rank increases, the methane adsorptive capacity of the coal increases, but not
as quickly as the total amount of methane generated, as shown in Exhibit 1-4. Therefore, the
amount of methane (and other gasses) produced during coalification generally exceeds the
retention capacity of the coal, and the excess methane often migrates into the surrounding strata.
EXHIBIT 1-4
METHANE GENERATION AND ADSORPTIVE CAPACITY
Thermal Maturity
Lignite
Sub
High
Vol.
Mw).
Vol.
Low
Vol.
Bituminous
Sťml
M*U
Anthracite
Graphite
Source: Decker, A.D., 1989.
12
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While over 180 cubic meters of methane per metric ton of coal can be generated as coal
progresses from peat to anthracite, the quantity of methane retained in exhumed coal is
substantially less. For example, the highest gas content measured for anthracite coal in the
United States is 21.6 cubic meters per metric ton, only 12 percent of the total theoretical amount
of methane generated during coalification.6 This is because 1) the quantity of methane
generated by coal generally exceeds the coal's adsorptive capacity and more importantly, 2) the
pressure holding the methane in coal is much less today than when the methane was generated.
Because pressure increases with depth, deeper coal seams will generally hold larger
quantities of methane than shallow coal seams of similar rank, as shown in Exhibit 1-5. In
addition, as the coal rank increases, the quantity of adsorbed methane also increases. This
relationship has been documented for coals throughout the world by numerous authors.7 The
methane content versus depth relationship is important for assessing future methane emissions
from coal mines. Since much of the shallow, high quality coal has been mined (especially in the
major non-United States coal producing countries), future coal mines will have to exploit deeper
coal reserves which will lead to increased methane emissions to the atmosphere.
Methane Flow
The flow of methane through coal seams differs from the gas flow mechanisms of
conventional reservoirs. As shown in Exhibit 1 -6, methane transport in coal has three distinct
properties: desorption from the coal surfaces, diffusion through the coal matrix, and flow through
the coal seam fracture system.
As mentioned previously, methane is stored in coal through the adsorption of methane
molecules on the coal's internal surface area. When pressure on the coal seam is lowered, either
6 Diamond, W.P., LaScola, J.C., and Hyman, D.M., 1986.
7 See, for example: Eddy, G.E., Rightmire, C.T., and Byrer, C.W., 1982; Kelafant, J.R. and Boyer, C.M., 1988;
Kelso, B.S., Wicks, D.E., and Kuuskraa, V.A., 1988; Johnston, DP and White, M.G.J., 1988; Shenyang Municipal
Gas Corporation, 1989; and Basic, A. and Vukic, M., 1989.
13
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EXHIBIT 1-5
RELATIONSHIP BETWEEN ADSORBED METHANE VOLUMES
AND DEPTH AND PRESSURE FOR DIFFERENT COAL RANKS
I
100
(325)
1
140
I
200
(650)
I
280
I
l
300 400
(975) (1300)
DEPTH
I I
420 560
PRESSURE, psi
i
500
(1625)
I
700
I
600
(1950)
I
840
700
(2275)
980
m
(ft)
Source: Kim, A.G., 1977.
through mining activities or through natural erosion, this methane is released (or begins to
"desorb") and flows through the coal matrix.8 After desorbing from the coal surface, the
movement of methane through the coal is controlled by the concentration gradient of methane
8 For more information on methane flow in coal, see McElhiney, J.E., Koenig, R.A., and Schraufnagel, R.A.,
1989.
14
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EXHIBIT 1-6
THE TRANSPORT OF METHANE GAS IN COAL
MICROPOROUS NETWORK
.
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millimeters to tens of centimeters, and appears to be related to coal rank and composition.9
Typically, cleat systems become progressively better developed as coal rank increases. A
schematic illustration of the coal cleat system is shown on Exhibit 1 -7.
The size, spacing, and continuity of the cleat system control the flow of methane once it
has diffused through the coal. Flow in the cleat system is described by D'Arcy's dynamic flow
equations, with free gas moving as a result of a pressure gradient. A summary of this two-step
process of methane flow in coal is shown in Exhibit 1 -6.
EXHIBIT 1-7
SCHEMATIC ILLUSTRATION OF THE
COAL CLEAT SYSTEM (PLAN VIEW)
Butt Cleat
Prepared by: ICF Resources, 1990.
9 Stach, E., 1975.
16
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Each coal has a characteristic "sorption time" that includes the time required for methane
molecules to desorb off of the coal surface and diffuse through the coal into the cleat system.
A coal's sorption time can vary from less than one to over 300 days, depending on coal
composition, rank, and cleat spacing. The rate at which methane desorbs and diffuses
determines the stage in the coal mining and utilization process at which the methane is emitted.
A coal with a short sorption time of one or two days, for example will emit most of its methane
during mining operations, while a coal with a long sorption time of 100-200 days will emit much
of its methane during post-mining coal processing.
Measuring the Methane Content of Coal
Various techniques have been developed to measure the methane content of coal. The
Direct Method, initially developed in France, has been standardized by the U.S. Bureau of Mines
(USBM) for measuring the quantity of methane in coal seams.10 The measurements are
performed on coal samples that have been recovered from mine workings or from wells drilled
into the coal seam. The coal sample is collected and placed in a sealed canister, and the
quantity of methane released is measured over time. When the coal sample ceases to emit
measurable quantities of methane, the sample is crushed to release the remaining methane. This
method can take anywhere from less than 1 to over 12 months, depending on the sorption time
of the coal. The total methane content of the coal sample is then obtained from three
components:
Lost Gas: the quantity of methane estimated to have been lost
during the recovery of the coal samples, prior to sealing the coal
in the canister.
Desorbed Gas: the quantity of methane desorbed from the coal
sample while it is sealed in the canister.
10 For information on the French development of the Direct Method, see Bertard, C., Bruyet, B. and Gunther J.,
1970. For information on USBM work on the method, see Diamond, W.P. and Levine, J.R., 1981; or Kissell, F.N.,
McCulloch, C.M., and Elder, C.H., 1973.
17
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Residual Gas: the quantity of methane emitted after grinding the
coal sample to a fine particle size.
The total quantity of methane obtained from these three components is compared to the mass
of the sample, with the resulting methane content reported as a volume of methane per mass of
coal, usually cubic centimeters per gram, cubic meters per metric ton, or cubic feet per standard
ton.11
The USBM methodology has been slightly modified by other researchers, but its basic
principles still hold as the industry standard.12 The modifications included standardizing the
volume of methane desorbed to standard pressure and temperature conditions (STP) and
accounting for differences in sample collection methods, especially those relating to deep core
wells or natural gas wells.
11 These units are related as follows:
1 cubic centimeter per gram = 1 cubic meter per metric ton = 32.04 cubic feet per standard ton
Note that there are 35.31 cubic feet in a cubic meter at STP and 1.1 standard tons in a metric ton.
12 Kissell, F.N., 1981.
18
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CHAPTER II
METHANE EMISSIONS DURING COAL MINING
The methane in coal remains adsorbed until pressure on the coal is lowered, which
causes the release and flow of methane. The development of a coal mine inevitably leads to
pressure reduction and causes methane to flow into the mine workings and then to the
atmosphere. This chapter describes the relationship between various mining methods and
methane emissions during mining. It then discusses the methane control measures currently
practiced in the coal mining industry and the effect of post-mining processing and utilization of
the coal on methane emissions.
Methane Emissions During Coal Mining
During coal mining, methane is emitted from the coal seam being mined and, in varying
degrees, from the methane-charged coal seams and rock strata that lie above and below the
mined seam. Most coal-bearing strata throughout the world contain a number of thin,
unmineable seams that are associated with the main seam, as shown in Exhibit 2-1. The amount
of methane released by mining activities thus depends on the methane content of the coal and
its surrounding strata. In general, larger methane emissions are associated with underground
mining than with surface mining because the deeper coals are under greater pressure and can
hold more methane.
Underground Mining
Underground mining accounted for about 40 percent of total United States coal
production in 1987 and about 45 percent of world-wide coal production.13 Underground mining
13 EIA Coal Production. 1987; EIA Coal Information. 1987.
19
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EXHIBIT 2-1
REPRESENTATIVE STRATIGRAPHIC COLUMNS FOR
FOUR COAL BASINS OF THE WORLD
SEAM THICKNESS
;METERS)
05
1 0
30
1 5
3.0
40
1.5
35
5.0
25
0.5
1.5
0.5
SEAM THICKNESS
(METERS)
SONGMING BASIN, CHINA
(FROM ZHAO. 1966)
1 0
1 5 -fe--s
SEAM NAME
WAYNES8URG COAL
4LIMESTONE
UNIONTOWN COAL
BENWOOO CARBONATES
SEWICKLEY COAL
REDSTONE COAL
______ PITTSBURGH COAL
APPALACHIAN BASIN, U.S.
(FROM DONAHUE AND ROLLINS, 1979)
SEAM NAME
FRITZ
ALFRED UPPER
ALFRED LOWER
GUS
UPPER OUNDAS
LOWER DUNOAS SPLIT
LOWER DUNOAS
COKING
SEAM THICKNESS
(METERS)
0,4
0,5
1.5
0,7
SEAM
THICKNESS
(METERS)
2.1
S2
2.4
2.1
3.7
SEAM NAME
MORANBAH E
MORANBAH 0
MIDDLE
GOONYELLA
MORANBAH C
MORANBAH 8
MORANBAH A
VRYHBD COALFIELD, SOUTH AFRICA
(FHOMCOMM OFINO INTO THE COAL RESOURCES. S.A.)
BOWEN COAL BASIN. AUSTRALIA
(FROM JOHNSON AND WHITE. '9881
Prepared by: ICF Resources, 1990.
20
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is typically pursued when coal seams are buried at depths greater than 60 meters. Two
underground mining methods are commonly used-room and pillar mining and longwall mining-
and these methods can result in different methane emissions levels.14
During underground mining, methane emissions begin with the development of the mine
works, including the construction of shafts and tunnels to access the buried coal seam. Mine
entries can be vertical or inclined depending on the depth of the coal seam. Inclined slopes are
typically used only if the seam is less than 300 meters deep, while vertical shafts can be used
at any depth. Whether inclined or vertical, however, these entries are used to transport personnel
and equipment and also serve as pathways for ventilation air, which is circulated throughout the
mine in order to dilute and remove the emitted methane.
Room and Pillar Mines. Room and pillar mining is the most common underground
mining method used in the United States. In this method, two or more sets of entries are driven
into the coalbed from the base of the entrance shaft. About every 100 meters, side entries are
driven from the main entries at 45 to 90 degree angles. From these latter entries, rooms 5 to 6
meters wide and about 15 meters apart are created by extracting the coal. The block of coal left
in between the rooms is called a pillar, and it supports the mine roof. Exhibit 2-2 shows the
sequential development of a room and pillar mine. The coal is extracted using either mechanical
mining machines (continuous miners) or by blasting and loading.
In the room and pillar method, 30 to 60 percent of the coal remains in the pillars after the
rooms are mined. Once the mining operation has extended the entries to their maximum length
and all of the coal has been removed from the rooms, the pillars may then be removed. The
pillars farthest from the mine opening are removed first and those nearest the shaft or slope are
removed last. To mine the pillars, temporary supports are built (usually constructed of timber)
and the pillar of coal is either partially or entirely removed. The extent of pillar removal depends
on many factors, including the integrity of the mine roof, the strength of the coal, and the
geometry of the pillars. In some cases, the pillars may be completely extracted safely, causing
14 For more information on coal mining, see Crickmeyer, D.F. and Zegeer, DA, editors, 1981, or Stefanko, R.,
1983.
21
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EXHIBIT 2-2
SCHEMATIC DIAGRAM OF THE DEVELOPMENT
OF A ROOM AND PILLAR MINE
5. Roof Bolt
Conventional
Mining
1. Undercut or
Top-cut Coal
Face. Drill Holes
for Explosives
4. Load Coal
Shoot
Load
Charge
Coal-Cutting
Machine
Train Haulage
Loading Machine
Shuttle Car
Pillar
Continuous
Mining Machine
Conveyor Belt
Continuous Mining
Source: EIA Coal Data: A Reference. 1989.
eventual total roof collapse; in other cases, it may not be possible to safely remove any of the
pillar which would cause limited or no collapse of the roof strata.
In room and pillar mining, methane is emitted by the coal that is mined, by the exposed
surfaces of the pillars and by the coal beds above and below the mined seam. The amount of
methane emitted by the surrounding strata is variable in room and pillar mining and depends on
the extent to which the roof fractures and collapses. Typically, the collapse of the overlying strata
and subsequent fracturing is not as extensive as that which occurs in longwall mines because
22
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any pillars or timbers left behind after mining can provide partial support to the roof strata and
prevent complete collapse.
Longwall Mines. Longwall mining was originally developed in Europe in the 1800's and
is presently the primary mining method employed there. The technique was introduced in the
United States in the 1960's and accounted for about 25 percent of United States underground
coal production in 1987 (about 84 million metric tons). Longwall mining is an extremely efficient
and rapid method of mining coal, with ultimate resource recovery approaching 85 percent.
However, the cost of equipping a longwall mine is much higher than that associated with
equipping a conventional room and pillar mine.
There are two basic types of longwall mining: retreat and advance. The two methods
are similar in the technologies employed and the associated methane emissions. Retreat
longwall mining is used extensively in the United States longwall mines, and it is the method
described here.
The development of a longwall mine begins by blocking out sections of coal into panels
that can be 3,000 meters in length and from 90 to 300 meters in width. The development of
panels is typically accomplished using continuous miners to drive entry ways (or gate roads)
down the length of the panel, as shown in Exhibit 2-3. Once the side entries are completed, a
set of entries is driven along the back of the panel to connect them.
After the panel is defined, movable coal cutting tools, a conveyor system, and a hydraulic
roof support system are positioned lengthwise in the back entry. The cutting equipment and
conveyor system operate underneath the roof support system. The cutting machine passes back
and forth along the face of the coal exposed when the back entry was driven and cut coal falls
onto the conveyor and is removed from the face. As the coal is removed, the hydraulic roof
supports, along with the cutting and conveyor equipment, advance.
When the hydraulic roof support system is moved, the unsupported roof strata in the
mined-out areas collapses. The floor strata also buckle creating a highly fractured zone above
and below the mined-out coal seam. This fractured and collapsed area is called a "gob" (or
23
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EXHIBIT 2-3
SCHEMATIC DIAGRAM OF LONGWALL MINE DEVELOPMENT
Longwall Mining Machine
(Works back and forth
across coal face)
Conveyor SS:
Be t wS
Self-Advancing .>/;;' :V,;:-- ;.;;v.. "'
Hydraulic :; :;.;.; ' .'/." :':''\;'!'.:/ ''''':'''':
Roof Supports ,';'' -v/,:;,: v' '-''.' ;':-;0-!";-:v>>
GOB Area
(Collapsed Roof Material)
Brattice
to Control
Ventilation
Pillar
Source: EIA Coal Data: A Reference. 1989.
"goaf) area. The size of the gob area is a function of the depth of the mined seam, the nature
of the rock overlying and underlying the coal seam, and the dimensions of the longwall panel.
However, the gob usually affects an area of at least 100 meters above and 30 meters below the
mined-out seam.15
Large volumes of methane are emitted during longwall mining operations both because
these mines are typically deep and because of the rapid rate of coal production. Nearly 180
million cubic meters of methane (6.3 billion cubic feet) were exhausted from the ventilation
15 Curl, S.J., 1978.
24
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system of the United States mine with the highest methane emissions in 1985.16 Much of the
methane is emitted from the thin coal seams and rocks fractured in the gob area.
Surface Mining
Coal seams that are less than 60 meters below the surface are generally produced using
surface mining techniques. Explosive charges fracture the strata overlying the targeted coal
seam. After the overburden has been fragmented, draglines or power shovels remove the
overburden and expose the coal seam.
As in underground mining, methane is released during surface mining by both the target
coal seam and by the surrounding strata and any adjacent coal seams. However, the methane
content of surface mined coal is estimated to be less than 3 cubic meters per ton (about 100
cubic feet/ton).17 To date, there have been no measurements of methane emissions from
surface mines because this methane is emitted directly into the atmosphere and poses no safety
hazard to the miners. Thus, the amount of methane emitted during surface mining is uncertain.
Methane Emission Control Measures
Methane is a serious safety threat in coal mining because it is highly explosive in
atmospheric concentrations of 5 to 15 percent. In the United States, the Mine Safety and Health
Administration (MSHA) requires close monitoring of methane levels and careful design of mine
ventilation systems to ensure that methane concentrations are kept at low levels. In mine entries
used by personnel, methane levels cannot exceed 1 percent and in certain designated areas of
the mine not frequented by mine personnel methane levels cannot exceed 2 percent. If these
concentrations are exceeded, MSHA requires that the coal production cease and that the mine
be evacuated until the ventilation system is able to dilute the methane concentration to
acceptable levels.
16 Grau, R.H., 1987.
17 For more information on these estimates, see Chapter III of this report and Exhibit 3-4.
25
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Research on methods of methane control in underground coal mines has been
undertaken because methane is such a serious and pervasive mining hazard, and because the
costs of elevated methane concentrations can be high in terms of lost coal production. The main
technique used for controlling methane concentrations in coal mines is ventilation. However,
other emission control measures-such as horizontal boreholes, cross-measure boreholes, gob
wells, and vertical degasification wells-have also been developed and are currently used in
mines with high methane emissions. Each of these control options are discussed below.
Ventilation
Ventilation is a universal methane control technique in underground mines. Federal
regulation requires that all coal mines continuously operate mechanical fans to circulate fresh air
across the actively mined coal face. To keep methane concentrations below acceptable levels,
several tons of air must be circulated through the mine for every ton of coal mined. For example,
the large mines in the Pittsburgh coal seam in Pennsylvania will circulate between 5 and 23 tons
of air for each ton of coal extracted.18
Currently, ventilation air is exhausted to the atmosphere at the mine shafts. Large
quantities of this air are vented, with methane concentrations typically under 1 percent. In 1985,
for example, the USBM estimated that 180 United States underground coal mines together vented
more than 3.1 billion cubic meters of methane (more than 110 billion cubic feet) to the
atmosphere through their ventilation systems. The ten largest methane emitting mines each
vented over 195,000 cubic meters per day (almost 7 million cubic feet per day) of methane in this
manner.19
Finding uses for these low concentration methane emissions has been the subject of
research by the USBM, the U.S. Department of Energy (DOE), and others. The USBM has
investigated the use of molecular sieves and membranes for stripping the low concentration
methane from the ventilation air and producing a more concentrated product. However, this
18 Skow, M.L, Kim, A.G., and Deul, M., 1980.
19 Grau, R.H., 1987.
26
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technology is not economic under current conditions. Another option under consideration is to
feed the ventilation air into a boiler. In this case, the boiler must be nearby because it is not
economic to transport low-energy ventilation air over large distances. Such an option might be
attractive at mines that generate their own power.
In many mines, methane emissions into the mine workings can be controlled using
ventilation alone by simply increasing the quantity of circulated air if methane concentrations are
too high. In some mines, particularly very deep or otherwise very gassy mines, using a
ventilation system alone to control methane would be prohibitively expensive. In these cases,
other degasification technologies must be employed in conjunction with mine ventilation.
Horizontal Boreholes
One method to supplement the ventilation system is to install horizontal boreholes, a
technique that has been used in coal mining since the 1800's. This technique consists of drilling
boreholes from the mine workings into the unmined areas of the coal seam, as shown in Exhibit
2-4. These boreholes are typically tens of meters to hundreds of meters in length, and within a
single mine several hundred boreholes may be drilled. The horizontal boreholes are connected
to an in-mine vacuum piping system, which transports all of the methane released into the
borehole out of the mine. Extensive precautions must be exercised to ensure that the integrity
of the piping system is maintained in the mine workings.
By draining methane from the unmined coal, horizontal boreholes reduce methane
emissions into the mine works and during mining. In some cases, 30 to 50 percent of the
methane contained in the coal seam being mined may be removed with horizontal boreholes.
Cross-Measure Boreholes
While horizontal boreholes can degasify the target coal seam, they cannot effectively
degasify the overlying or underlying coal and rock strata. To accomplish this type of
degasification, cross-measure boreholes are used. Cross-measure boreholes have been used
extensively in Europe but are not widely used in the United States.
27
-------
These boreholes are similar to horizontal boreholes except they are drilled at an angle into
the strata above and below the coal seam, usually into a future or active gob area, as shown in
Exhibit 2-4. These boreholes are most effective in draining methane only after the gob area is
created and the surrounding strata are fractured. As with horizontal boreholes, several boreholes
are typically drilled and connected to an in-mine piping system which transports the methane to
the surface.
EXHIBIT 2-4
SCHEMATIC DIAGRAM OF HORIZONTAL
AND CROSS-MEASURE BOREHOLES
Mined
Area
Unmined
Area
Prepared by: ICF Resources, 1990.
28
-------
Gob Wells
The fractured gob area produced by longwall mines and some room and pillar mines is
a significant source of methane, and in deep, gassy mines the ventilation system is often unable
to sufficiently dilute the methane emitted from the gob into the mine workings. In these
situations, wells can be drilled from the surface to drain methane from the gob area. Generally,
these wells are drilled to a point 2 to 15 meters above the mined seam prior to the mining of the
longwall panel. As mining advances under the gob well, the methane-charged coal and strata
around the well will fracture. The methane emitted from this fractured strata flows into the gob
well (often operating on a vacuum) and then to the surface, as shown in Exhibit 2-5.
EXHIBIT 2-5
SCHEMATIC DIAGRAM OF A GOB WELL
GobWM
n
Mined
Area
Unmined
Area
Prepared by: ICF Resources, 1990.
29
-------
Methane production rates from gob wells can be very high, especially immediately
following the fracturing of the strata as the longwall passes under the gob well. One mining
company that recovers methane from its gob wells for sale to a pipeline reports that the wells
may initially produce at rates in excess of 56,000 cubic meters per day (2 million cubic feet per
day). Over time, this production rate declines until a relatively stable rate is achieved, typically
in the 2,800 cubic meters per day (100,000 cubic feet per day) range.20 Initially, this gob gas
may be of pipeline quality (37 Kj/m3 or 1,000 Btu/ft3). Over time, the quality may fall as methane
emissions decline and additional amounts of mine air flow into the well and dilute the methane.
With careful monitoring of the vacuum exerted on the well, however, it may be possible under
certain conditions to maintain production of a high quality gas over much of the life of the well.
Most methane produced from gob wells is currently vented to the atmosphere. One
notable exception to this is in Alabama, where over 849,000 cubic meters of methane per day
(more than 30 million cubic feet per day) from 80 gob wells are captured and sold as natural gas.
Since this program was initiated six years ago, over 1.1 billion cubic meters (almost 40 billion
cubic feet) of methane have been captured and utilized instead of being vented to the
atmosphere.21 However, even this program has probably only captured 30 to 40 percent of
the methane released as a result of this mine's coal mining activities.
Vertical Wells
The optimum method for controlling methane emissions is to pre-drain the methane from
the coal and strata before mining operations begin. Vertical degasification wells are similar to
conventional oil and gas wells and are drilled into the coal seam several years ahead of the
active mining area. Usually, these wells must be stimulated to create a pathway in the coal to
facilitate gas flow. In addition, in some areas these wells may produce large quantities of water
and small volumes of methane during the first several months they are on-line. As this water is
removed, the pressure on the coal seam is lowered, the methane desorbs, and the methane
production rate increases, as shown in Exhibit 2-6.
20 Dixon, C.A., 1989.
21 Dixon, C.A., 1989.
30
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EXHIBIT 2-6
GAS AND WATER PRODUCTION CURVES FOR
A TYPICAL VERTICAL WELL
Rate
Producing Tim*
Prepared by: ICF Resources, 1990.
Pre-drainage of methane using vertical wells is a very effective method of reducing the
methane content of coal beds and, consequently, reducing the methane emissions from the
eventual mining operation. Diamond and others document that as much as 79 percent of the
methane in-place in the mined seam can be removed from coal using vertical degasification wells
drilled more than 10 years in advance of mining.22 Although vertical wells are not widely used
in the coal mining industry, their use is increasing in "stand-alone" gas production operations.
Post-Mining Emissions
The time required for a coal to release all of its methane can vary from several days to
22 Diamond, W.P., Bodden, W.R., Zuber, M.D., and Schraufnagel, R.Z., 1989.
31
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several months. Because the residence time in the mine of the mined coal is generally less than
one day, a portion of the methane is released after the coal has left the mine, during the
subsequent processing, transportation, and utilization.
Coal Processing
Coal processing involves transforming the mined coal into a product acceptable for sale.
Metallurgical coal is used to produce coke, a porous carbon solid derived from the destructive
distillation of coal. Coke is used in the smelting of iron ore and the manufacturing of steel.
Thermal coal is used to generate heat, which in turn is used for electric power generation,
industrial heating, and residential heating. The primary points during coal processing where
methane emissions are accelerated are breaking, crushing, and thermal drying.
The greatest amounts of post-mining methane emissions occur when the coal is crushed
and sized. The smaller coal size and the creation of increased surface area enables the methane
on these surfaces to rapidly desorb and be emitted. The two principal coal size reduction
processes are:
Primary breaking and crushing. During this initial breaking and crushing
methane emissions are high as the mined coal is reduced to 5-15 cm
lumps.
Secondary breaking and crushing. Additional breakage and methane
release results from the handling of the coal as it is blended, cleaned,
moved in storage, loaded and transported, unloaded, stored, and prepared
for use by the customer.
Drying is accomplished by blowing heated air through the coal in a drying chamber,
driving off the excess moisture. In metallurgical coals, the coal surfaces are generally the only
part that is dried. In some of the higher moisture thermal coals, the coal is dried more deeply
to remove a percentage of the internal (inherent) moisture as well. Because the desorption rate
of methane from coal is accelerated at elevated temperatures, thermal drying will accelerate
methane emissions. All methane emitted during size reduction and thermal drying is currently
vented to the atmosphere.
32
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Coal Transportation
World coal transportation is dominated by railroads, which account for over 60 percent
of total coal transportation. Transportation by barge and ship account for an additional 10 to 20
percent.23 The remaining transportation methods are divided among trucks, conveyors,
tramways, and slurry pipelines. The methane emissions from coal during transportation are
released directly to the atmosphere. Even in those transportation systems that are enclosed,
such as a ship's hold, the required ventilation system will ultimately exhaust the methane into the
atmosphere.
Coal Utilization
The largest use of coal is for the thermal coal market, accounting for about 80 percent
of world coal production. Metallurgical coal accounts for the remaining 20 percent of production.
For thermal coal, the remaining methane in the coal will be emitted during the final crushing and
pulverization of coal, prior to its use at the utility plant. Because this process occurs within a
closed system, the methane is burned along with coal upon injection into the boiler.
During the production of coke, the end-use for metallurgical coal, the coal is heated to
very high temperatures to drive off the volatile matter and to produce a nearly pure carbon
material. Prior to heating, the coal is often crushed to less than 5 mm, with the emitted methane
vented to the atmosphere. During the coking process, a mixture of methane, carbon dioxide, and
other gases are driven off and collected as coke gas. In modern coke ovens, the coke gas is
captured and utilized as a fuel source, although old coke ovens (known as "beehives") in use in
lesser developed countries still vent the coke gas into the atmosphere.
23 IEA Coal Information. 1987.
33
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34
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CHAPTER III
Methane Emissions Estimate For Global Coal Mining
One of the goals of this study was to estimate the quantity of methane emitted to the
atmosphere from coal mining and utilization both on a global and country-by-country basis.
While global estimates of methane emissions from coal mining and utilization have been prepared
previously as part of comprehensive studies of the global methane budget, these studies do not
provide information on methane emissions from coal mining by country, and in many cases they
do not fully document the methodology used to arrive at their estimates.
This study estimates country-specific methane emissions from coal mining, although these
estimates must be considered highly approximate because of data limitations and other
uncertainties. By providing broad country-by-country estimates, however, this report provides
information of use to scientists, technical experts and policy makers who need to set priorities
to guide additional research. Further, in developing and explaining the methodology used to
generate these estimates, the report can serve as a foundation for future research and for refining
the methodology used to prepare emission estimates for coal mining.
This chapter has four sections. In the first section, the methodologies used to estimate
methane emissions from United States coal mines is explained. In the second section, methane
emissions for other coal producing countries are estimated. The third section summarizes the
global estimates contained in this study and compares the estimates to others found in the
literature. Finally, the fourth section discusses the key uncertainties in this analysis and their
potential impacts.
35
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Methane Emissions From United States Coal Mines
Methodology
Methane emissions from coal mining and coal utilization in the United States were
determined on a state-by-state basis using data on the coal tonnage mined, the type of mining
used (underground or surface), the estimated methane content of the coal, and a mining-based
emissions equation. Data on coal production and type of mine were obtained from federal and
state reports. Where available, methane content data were obtained from measurements by
USBM, DOE, the Gas Research Institute (GRI), and industry. For those states with no methane
content data, a methane content value was estimated based on the rank and depth of the coal
seams being mined in the state. A mining-based emissions equation was used to estimate the
total methane emissions from a mine, including methane emissions from the mined coal, from
coal left in the mine, and from associated coal seams and strata. This factor was derived from
a statistical analysis of the measured methane emission rates from 59 United States mines. In
addition to estimating methane emissions from the mining operation itself, the quantity of
methane released by mine degasification systems and the various post-mining processes was
also estimated. Each of these steps is discussed in more detail below.
United States Coal Production Data. Coal production data for the United States in
1987 were obtained from official state reports and from the U.S. Energy Information
Administration.24 Because the methane content of shallow coal and deeply buried coal is
significantly different, coal production data were separated into underground and surface mining
categories, as shown in Exhibit 3-1. Five major coal producing states in the Appalachian Basin
(Kentucky, West Virginia, Pennsylvania, Virginia, and Ohio) accounted for over 70 percent of total
underground coal production. Wyoming dominated surface mined coal production with nearly
30 percent of total United States surface coal production.
United States Methane Content Data. Methane content values for underground and
surface mined coal were estimated for each coal producing basin and the associated states. The
24 1987 coal production data were used because this is the most recent year for which international coal
production data were available.
36
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EXHIBIT 3-1
UNDERGROUND, SURFACE, AND TOTAL COAL PRODUCTION
IN THE UNITED STATES, 1987
Coal Production (Thousand Metric Tons)
State
ALABAMA
ALASKA
ARIZONA
ARKANSAS
CALIFORNIA
COLORADO
ILLINOIS
INDIANA
IOWA
KANSAS
KENTUCKY
LOUISIANA
MARYLAND
MISSOURI
MONTANA
NEW MEXICO
NORTH DAKOTA
OHIO
OKLAHOMA
PENNSYLVANIA
TENNESSEE
TEXAS
UTAH
VIRGINIA
WASHINGTON
WEST VIRGINIA
WYOMING
TOTAL
Underground
12,999
0
0
0
0
5,115
34,039
2,220
57
0
83,592
0
2,177
0
0
562
0
1 1 ,440
0
34,623
4,366
0
14,976
33,322
0
97,224
96
Surface
10,099
1,354
10,323
61
42
7,959
19,623
28,781
367
1,829
64,933
2,496
1,384
3,885
31 ,207
16,794
22,807
20,812
2,590
28,376
1,395
45,840
0
6,757
4,036
26,094
133.125
Total
23,098
1,354
10,323
61
42
13,074
53,662
31,001
425
1,829
148,525
2,496
3,562
3,885
31 ,207
17,357
22,807
32,252
2,590
62,999
5,762
45,840
14,976
40,079
4,036
123,318
133.221
336,810
492,969
829,779
Source: EIA Coal Production. 1987.
37
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major coal basins in the United States are shown in Exhibit 3-2. Four techniques were used to
develop the methane content estimates, depending on the type and quality of the data available
and the mining method employed.
EXHIBIT 3-2
MAJOR U.S. COAL BASINS
AND COALBED METHANE RESOURCES
Western Washington
24Tcf
Wind River
2 Tcf
Greater
Green River
31Tcf
Uinta
1Tcf
Piceance'
84Tcf
Powder River
Illinois
Northern Appalachian*
61 Tcf
San Juan*
Fruitland Coal = 50 Tcf
Menefee Coal = 38 Tcf
Raton Mesa
18 Tcf
Warrior*
Alabama
20 Tcf
Central
Appalachian*
5 Tcf
* Detailed geologic appraisals completed by GRI/ICF Resources
Prepared by: ICF Resources, 1990.
Where available, detailed assessments of the quantity of methane content in coal
seams were used. To date, these assessments have been prepared by the GRI for five of the
major United States coal basins-Northern Appalachian, Central Appalachian, Warrior, San Juan,
and Piceance-which together accounted for 78 percent of United States underground coal
38
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production in 1987.25 These studies estimated the quantity of methane in coal seams more
than 400 feet deep. In each basin, a relationship between methane content and the depth and
rank of the coal seams was derived using data from the USBM Gas Content Database and other
available sources.26 Over 1,200 methane content measurements were used in these
evaluations. The methane content and depth/rank relationship for the Central Appalachian Basin
is shown in Exhibit 3-3.27
EXHIBIT 3-3
RELATIONSHIP BETWEEN GAS CONTENT AND DEPTH
CENTRAL APPALACHIAN BASIN
I
o
(A
3
700
600
500
400
300
200
100
LOW VOLATILE
MEDIUM
VOLATILE
... HIGH VOLATILE A
^
1000 2000
DEPTH (FEET)
3000
Source: Kelafant, J.R., and Boyer, C.M., 1988.
25 Kelafant, J.R., Wicks, D.E., and Kuuskraa, V.A., 1988; Kelafant, J.R., and Boyer, C.M., 1988; Kelso, B.S.,
Wicks, D.E., and Kuuskraa, VA, 1988; McFall, K.S., Wicks, D.E., and Kuuskraa, V.A., 1986; McFall, K.S., Wicks,
D.E., Kuuskraa, V.A., and Sedwick, KB., 1986.
26 Diamond, W.P., LaScola, J.C., and Hyman, D.M., 1986.
27 Kelafant, J.R., and Boyer, C.M., 1988
39
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The GRI assessments also provided an estimate of the tonnage of coal present in the basins,
which was combined with the estimated methane content to determine an average methane
content for underground mined coal in each basin.
In four other key coal producing areas (the Uinta, Illinois and Green River Basins, and
the Pennsylvania Anthracite fields) methane content data were available but the basins have not
been studied in detail. For three of these basins28, methane and coal resource estimates
prepared by the DOE were used to approximate the methane content of underground mined
coal. For the fourth basin29, no basin-wide methane and coal resource estimates were
available and the methane content of underground mined coal was estimated from the arithmetic
average of the available methane content data for the basin.
Available data on the methane content of surface mined coal were also obtained from
the USBM Methane Content Data Base.30 For these estimates, only methane content values
measured in coal seams less than 200 feet deep (the approximate depth limit for surface mined
coal) were used. The average methane content of surface-mined coal was the arithmetic average
of the shallow coal methane content values.
Finally, no methane content data were available for some of the smaller coal basins
in the United States. For these basins, average methane content values were derived by analogy
with coal basins with methane content estimates, based on the rank, depth, and age of the coal
being mined. Exhibit 3-4 summarizes the methane content estimates used for the different coal
basins.
Mining Emissions Equation - Underground Mines. During the mining of coal, the
total quantity of methane emitted from the mine exceeds the in-situ methane content of the mined
coal. This difference is due to 1) methane emissions from coal pillars left in the mine for support
and, more importantly, 2) methane emissions from the methane charged coal seams and rock
28 Illinois, Uinta, and Green River Basins.
29 Pennsylvania Anthracite Fields.
30 Diamond, W.P., LaScola, J.C., and Hyman, D.M., 1986.
40
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EXHIBIT 3-4
AVERAGE METHANE CONTENT
IN MINED COAL
Estimated
Basin or State Average Methane Content
(m /metric ton)
Underground Mined Coal
Northern Appalachian1 5.4
Central Appalachian2 10.4
Warrior3 10.0
Piceance4 8.0
San Juan5 7.1
Illinois6 1.8
Uinta6 1.3
Green River6 1.3
Pennsylvania Anthracite Fields7 4.4
Surface Mined Coal
Appalachian (including Warrior)7 1.55
Illinois7 1.22
Powder River7 0.10
Arkoma7 3.40
San Juan7 0.48
Alaska8 0.10
Arizona9 0.48
Arkansas10 1.22
California8 0.10
Louisiana8 0.10
North Dakota8 0.10
Texas8 0.10
Washington8 0.10
1) Kelafant, J.R., Wicks, D.E., and Kuuskraa, V.A., 1988
2) Kelafant, J.R., and Boyer, C.M., 1988
3) McFall, K.S., Wicks, D.E., and Kuuskraa, V.A., 1986
4) McFall, K.S., Wicks, D.E., Kuuskraa, V.A., and Sedwick, K.B., 1986
5) Kelso, B.S., Wicks, D.E., and Kuuskraa, V.A., 1988
6) Mroz, T.H., Ryan, J.G., and Byrer, C.W., 1983
7) Diamond, W.P., LaScola, J.C., and Hyman, D.M., 1986
8) Extrapolated from the Powder River Basin
9) Extrapolated from the San Juan Basin
10) Extrapolated from the Illinois Basin
41
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strata surrounding the mined seam. The quantity of methane emitted varies from mine to mine
depending on mining method, tonnage mined, and the age of the mine. One study by the
USBM, shown in Exhibit 3-5, indicated that the methane emissions during mining exceeded the
in-situ methane content by a factor ranging from 6 to 9.31 Methane emissions factors for
EXHIBIT 3-5
METHANE EMISSIONS VS. IN-SITU METHANE CONTENT
SELECTED U.S. COAL MINES
I"
1.
10 -
/ HOW.
Loverldp Q Federil No. 2
>
blind
I I I I I I 1 1 I I
2 46 8 10 12 14 16 18 20
In-ani nwthm coaunt, ii|3/t
Source: Kissell, F.N., McCulloch, C.M., and Elder, C.H., 1973.
31 Kissell, F.N., McCulloch, CM, and Elder, C.H., 1973.
42
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mining have also been estimated in other major coal producing countries of the world (especially
the European countries), yielding methane emissions factors ranging from 2 to S.32
The most accurate method of calculating methane emissions would be to derive an
emissions factor for every mine of interest. For United States mines, data on methane emissions
are publicly available through MSHA and from periodic summary reports by the USBM. Given
that there are almost 1,900 active underground mines in the United States alone, however, such
an analysis was beyond the scope of the study.
Thus, the methane emissions estimates derived by this study were based on a United
States average methane emissions equation, which was derived using data from a previous study
on methane emissions and the previously described GRI basin assessments.33 A comparison
was made between actual methane emissions (per ton of coal mined) and the estimated in-situ
methane content (per ton of coal mined), similar to the approach used by the USBM in 1973 and
shown in Exhibit 3-5. Results of this comparison and a least-squares linear regression of the
data are shown in Exhibit 3-6. In addition, the least squares linear regression and a 1 -standard
deviation range of the data are also shown. The equation obtained from the linear regression,
in cubic meters of methane emitted per metric ton of coal mined, is:
Methane Emissions, in Cubic Meters of Methane per Metric Ton of Coal Mined =
(2.04 x In-Situ Methane Content) + 8.16
(t Statistic = 5.10, r2 = 0.35)
Both the scatter plot of the regression and the r-squared of the regression indicate that there is
a great deal of uncertainty with respect to methane emissions per ton of coal mined. Using one
standard deviation around the mean (regression line) as a measure of uncertainty, it appears that
the actual methane emissions value could be up to 23 percent higher or lower than the predicted
level.
32 Curl, S.J., 1978.
33 Irani, M.C., Jeran, P.W. and Deul, M., 1974.
43
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EXHIBIT 3-6
METHANE EMISSIONS VS. IN-SITU METHANE CONTENT -
59 U.S. COAL MINES
80
c
o
in
O
in
70 -
-H eo H
E 50 -
40 -
30 -
ra 20 -
10 -
n
n
n n
n
n
n
I
10
\
12
n
I
14
6 8
In-Situ Methane Content, m^/metric ton
16
i
18
20
Source: Irani, M.C., Jeran, P.W., and Deul, M., 1974, and ICF Resources, 1990.
This equation was combined with the average in-situ methane contents established for
the various coal producing states to estimate the methane emissions per ton of coal mined.
When combined with the tons of underground coal production from each state, an overall
estimate of the quantity of methane emitted from underground mines was obtained. A range of
methane emissions was also estimated to reflect the uncertainties inherent in these estimates.
Mining Emissions Factor - Surface Mines. The methane contents of surface mined coal
seams are substantially lower than those of deeper, underground mined coal seams, as
44
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discussed previously. The quantity of methane emitted from surface mines may be significant,
however, since surface mined coal represents nearly 60 percent of the total coal production in
the United States.
As with underground mines, the total quantity of methane emitted by surface mines will
always be larger than the quantity of methane contained in the coal being mined, because of the
contribution of methane from the coal seams and strata adjacent to the mined seam that are
disturbed during mining. Because of this, the previously established methane emission equation
should be applicable to surface mined coal. However, surface coal mines typically have higher
coal recovery rates (80 percent) than underground coal mines (50 percent). The underground
mining emissions equation (derived from underground coal production and methane emissions
rates) was therefore modified to account for the increase in coal recovery associated with surface
coal mines. The estimated methane emissions (per ton of coal mined) for surface mined coal
were decreased by 37.5 percent to incorporate the higher recovery rates associated with surface
mines.
Degasification System Emissions. Many underground mining operations in the United
States employ degasification systems to control methane levels in the mine workings. With the
exception of a limited number of mines, primarily in Alabama, all of the methane produced by
degasification systems is vented to the atmosphere and must be included in any estimate of total
mining-related methane emissions.34 Estimates of methane produced from gob wells
associated with longwall mining operations were used to represent the contribution from
degasification methods to the total methane emissions estimate. It is recognized that other
degasification systems, such as horizontal and cross-measure boreholes or vertical wells, also
produce and emit methane but these systems were not included in this estimate.
In 1987, 101 longwall systems were operating in the United States.35 For this study, it
was assumed that it would take an average of nine months to completely mine a longwall panel,
which would imply that a total of 133 longwall panels could have been mined in 1987. The
34 The USBM data on which the emission equation was based measures methane contained in the ventilation
air only. Thus, this equation alone would not reflect the additional methane emissions from degasification systems.
35 Layne, A.W., Siriwardane, H.J. and Byrer, C.W., 1988.
45
-------
number of gob wells producing from each longwall panel varies depending upon the length of
the panel and the quantity of methane to be vented. In addition, the length of time these wells
vent methane and the quantity of methane vented also vary. In this analysis, it was assumed that
three gob wells per longwall panel would be drilled and that they would vent methane for about
nine months.36 An average methane emission rate of 14,160 cubic meters per day (500,000
cubic feet per day) per well was used for gob wells in all states, with the exception of
Alabama.37 Based on published data from 80 gob wells, an average gob well emission rate
of 25,485 m3/day (900,000 cubic feet per day) was used for Alabama.38
Based on these assumptions, an estimated 2.2 billion cubic meters (over 77 billion cubic
feet) or 1.5 million metric tons of methane was emitted to the atmosphere from degasification
systems. Thus, these emissions could account for 20 percent of total methane emissions. Only
one state, Alabama, currently has mining operations which utilize this methane rather than
venting it to the atmosphere. In 1987, mining operations in Alabama captured and sold almost
310 million cubic meters (10 billion cubic feet), or about 0.2 million metric tons, of methane into
the natural gas pipeline systems. The utilized methane was not included in the 1.5 million metric
tons estimated as being vented by degasification systems.
Post-Mining Emissions. Because methane desorption and emission is not
instantaneous, some methane will still be contained in the coal after it has left the mine. It was
estimated that, on average, 25 percent of the methane content of mined coal (i.e., the in-situ
methane content) could be emitted after the coal has left the underground mine.
36 The number of gob wells per panel and their production lifetime are variable, dependent upon specific
geologic and mining conditions at the subject mine. Currently, the optimal number of wells is determined often by
trial and error, and has ranged from one to six wells per panel. In this analysis, rt was assumed that three wells
would be used, which is consistent with the selection of a three-well spacing reported by Dixon, C.A., 1989, for
certain mines in Alabama.
37 Layne, A.W., Siriwardane, H.J., and Byrer, C.W., 1988; Pothini, B.R., 1988; Kline, R.J., Mokwa, L.P., and
Blankenship, P.W., 1987.
36 Alabama State Oil and Gas Board, 1986-1989; Dixon, C.A.. 1989.
46
-------
Results
The total methane emissions estimate for the United States during 1987 was derived from
three separate categories of emissions: emissions directly from the mine for both underground
and surface mines; emissions from degasification activities associated with underground mines,
and post-mining emissions from underground-mined coal. Based on this study, an estimated 7.0
million metric tons (with a range of 5.4 to 8.6 million metric tons) of methane were emitted to the
atmosphere as a result of coal mining and utilization in 1987 in the United States, as shown in
Exhibit 3-7. By far the largest source of methane emissions was the mining operation itself. In
the United States, 4.2 to 6.6 million metric tons of methane, or about 78 percent of the total
methane emissions, were released directly from the mine workings. Methane emissions from
degasification systems accounted for about 18 percent of the total emission (1.0 to 1.5 million
metric tons) and post-mining methane emissions contributed the remaining 4 percent of the total
(0.2 to 0.4 million metric tons), Exhibit 3-8.
Of the total methane emitted, about 88 percent (4.7 to 7.5 million metric tons) came from
underground mined coal and the remaining 12 percent (0.6 to 1.1 million metric tons) was
released from surface mined coal. Four states - West Virginia, Virginia, Pennsylvania, and
Alabama - accounted for almost 75 percent of the total United States emissions. In these states,
deep longwall mines are the major source of methane emissions.
In addition, average methane emissions per ton of coal mined using underground or
surface methods were estimated by dividing estimated emissions from each mining method by
the total amount of coal mined using that method. This approach yielded estimated emissions
of 27.1 cubic meters of methane per metric ton for underground mined coal and 2.5 cubic meters
of methane per metric ton for surface mined coal. These estimated methane emission values are
not representative of any specific mine or area because they represent the aggregate of all
United States coal mines and basins. They reveal a significant difference in emissions between
underground and surface mines, however, and can also provide a useful benchmark for
comparison with other studies.
47
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EXHIBIT 3-7
ESTIMATED METHANE EMISSIONS FROM U.S.
COAL MINING AND UTILIZATION
BY STATE, 1987
State Estimated Methane Emissions
(Million Metric Tons)
Underground Surface Total
ALABAMA 0.3 <0.1 0.3
ALASKA 0 <0.1 <0.1
ARIZONA 0 <0.1 <0.1
ARKANSAS 0 <0.1 <0.1
CALIFORNIA 0 <0.1 <0.1
COLORADO 0.2 <0.1 0.2
ILLINOIS 0.4 0.1 0.5
INDIANA <0.1 0.1 0.1
IOWA <0.1 <0.1 <0.1
KANSAS 0 <0.1 <0.1
KENTUCKY 0.8 0.2 1.0
LOUISIANA 0 <0.1 <0.1
MARYLAND 0.1 <0.1 0.1
MISSOURI 0 <0.1 <0.1
MONTANA 0 <0.1 <0.1
NEW MEXICO <0.1 <0.1 <0.1
NORTH DAKOTA 0 <0.1 <0.1
OHIO 0.3 <0.1 0.3
OKLAHOMA 0 <0.1 <0.1
PENNSYLVANIA 0.6 0.1 0.7
TENNESSEE <0.1 <0.1 <0.1
TEXAS 0 <0.1 <0.1
UTAH 0.2 0 0.2
VIRGINIA 0.9 <0.1 0.9
WASHINGTON 0 <0.1 <0.1
WEST VIRGINIA 2.3 0.1 2.4
WYOMING <0.1 <0.1 0.1
TOTAL 6.1 0.9 7.0
POTENTIAL RANGE 4.7-7.5 0.6-1.1 5.4-8.6
48
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Mine
Operations
4.6 (3.6-5.5)
0.9(0.6-1.1)
5.5 (4.2-6.6)
Degasification
Svstems
1.2(1
0
1.2(1
.0-1.5)
.0-1.5)
Post-Mining
Processes
0.3 (0.2-0.4)
0
0.3 (0.2-0.4)
Total
6.1 (4.7-7.5)
0.9(0.6-1.1)
7.0 (5.4-ae)
EXHIBIT 3-8
ESTIMATED METHANE EMISSIONS FROM U.S. COAL MINING AND UTILIZATION
BY MINING METHOD AND SOURCE
Estimated Methane Emissions (Million Metric Tons)
Mine
Mining Method
Underground
Surface
Total (Range)
Methane Emissions from Foreign Coal Producing Countries
As indicated by the discussion above, estimating methane emissions from coal mining is
very data-intensive. Even in the United States, where data on coal production, in-situ methane
content, and methane emissions through mine ventilation systems are collected and analyzed,
the estimates are based on major assumptions and have a degree of uncertainty. Estimating
methane emissions from coal mining in other countries is even more uncertain because access
to data is limited, particularly in some of the other major coal producing nations such as China,
the Soviet Union, and Poland.
Since efforts to collect and assess data from the many coal producing countries was
beyond the scope of this study, methane emissions from United States coal mines were used
as the analog for estimating methane emissions from other coal producing countries of the world.
To estimate country-specific methane emissions, the estimated average methane emission rates
for surface and underground mining in the United States were combined with the 1987 coal
production of each country. To reflect the uncertainty inherent in applying these values to other
countries, the United States methane content ranges were expanded by an additional 10 percent.
Thus, the methane content ranges used to estimate international methane emission were 18.8
to 36.7 m3/ton for underground mined coal and 1.7 to 3.4 m3/ton for surface mined coal.
49
-------
This assumption reflects the fact that actual methane emissions could be higher or lower
than those estimated for the United States depending on factors such as (1) the methane content
of coal being mined, (2) the age of the mine, (3) the type of mining method used, and (4) the
type of degasification systems used. As better data become available for various countries,
country-specific mining emissions equations should be created and these estimates refined.
Until such data are available, however, this approach represents a reasonable first
approximation of country-by-country methane emissions associated with coal mining. Because
it distinguishes between underground and surface mining, the major source of variation in
methane emissions is accounted for. Further, since the coal ranks mined in the United States
are generally similar to those mined in other coal producing countries, the approach should
provide a reasonable estimate of emissions. Finally, while it is difficult to determine a particular
country's emissions with certainty, this method provides information about the order of magnitude
of emissions between different countries, which is important to both policy makers and technical
researchers in developing priorities for future research efforts.
Coal production statistics were collected from a number of sources including United
States Department of Energy reports, World Bank studies, and various foreign country
on
reports. Underground and surface coal production in 1987 for the ten largest foreign coal
producing countries is shown in Exhibit 3-9. These ten countries represent 85 percent of total
foreign coal production, producing 3.2 billion metric tons of coal out of a foreign total of 3.8
billion metric tons of coal. China was the largest coal producing country, with more than 900
million metric tons of reported coal production in 1987.
Estimated methane emissions from United States and foreign coal mining activities is
shown in Exhibit 3-10. The figure is divided to show methane emissions from the ten largest
foreign coal producing countries (and the United States) and the secondary coal producing
countries. As the exhibit shows, the methane emissions from the ten primary foreign coal
producing countries are estimated to account for over 90 percent (34 to 54 million metric tons)
of the total world methane emissions (33 to 64 million metric tons). China, the world's largest
39 See for example, IEA Coal Information. 1987; IEA Coal Statistics. 1987; EIA Coal Production. 1987.
50
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EXHIBIT 3-9
UNDERGROUND, SURFACE, AND TOTAL COAL PRODUCTION IN THE
TEN PRIMARY FOREIGN COAL PRODUCING COUNTRIES, 1987
1987 Coal Production (Million Metric Tons)
Country Underground Surface Total
China 891 37 928
U.S.S.R 429 331 760
East Germany 0 303 303
Poland 193 73 266
Australia 47 143 190
West Germany 79 109 188
India 85 100 185
South Africa 111 62 173
Czechoslovakia 26 100 126
United Kingdom 86 16 102
TOTAL 1,947 1,274 3,221
Source: IEA Coal Information. 1987; IEA Coal Statistics. 1987; EIA Coal Production. 1987.
coal producer, was estimated to release 34 percent (12 to 20 million metric tons) of the world's
methane emissions. The top four foreign coal producers-China, the Soviet Union, the United
States, and Poland-were responsible for about 75 percent (27 to 43 million metric tons) of the
world's estimated emissions.
Coal mining operations in many European countries employ extensive degasification
systems.40 Of the methane produced by the degasification methods, from 5 to 90 percent is
utilized as a fuel source. Using these published values of methane production and utilization,
it is estimated that over 8 million metric tons of methane were produced from degasification
systems in the primary foreign coal producing countries and that nearly 2 million metric tons, over
20 percent, was utilized. The highest methane emission utilization rates are in the mines of
Poland, West Germany, and the United Kingdom.
40 Curl, S.J., 1978.
51
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EXHIBIT 3-10
ESTIMATED WORLD METHANE EMISSIONS FROM COAL MINING
Primary Coal Producing Countries
China
U.S.S.R.
United States
East Germany
Poland
Australia
West Germany
India
South Africa
Czechoslovakia
United Kingdom
Subtotal
(Range)
Estimated Methane Emissions (Million metric tons)
Underground Surface Total
16.0
7.7
6.1
0
3.3
0.9
1.4
1.5
2.0
0.4
40.8
(28.3 - 55.2)
0.1
0.6
0.9
0.5
0.1
0.2
0.2
0.2
0.1
0.2
3.2
(2.2 - 4.3)
16.1
8.3
7.0
0.5
3.4
1.1
1.6
1.7
2.1
0.6
1.6
44.0
(30.5 - 59.5)
Secondary Coal Producing Countries
North Korea
South Korea
Spain
France
Japan
Canada
Turkey
Brazil
Mexico
Yugoslavia
Belgium
Zimbabwe
Colombia
Subtotal
(Range)
0.7
0.4
0.2
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
2.3
(1.6-3.1)
0
0.1
0.1
0
0
0.1
0
0
0.3
(0.2 - 0.4)
0.7
0.4
0.3
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
2.6
(1.8-3.5)
Other Coal Producing Countries
(Range)
0.6
(0.4 - 0.8)
0.2
(0.1 - 0.3)
0.8
(0.6- 1.1)
TOTAL ESTIMATED METHANE EMISSIONS 43.7 3.7 47.4
FROM COAL MINING (RANGE) (30.3 - 59.1) (2.6 - 5.0) (32.8 - 64.1)
Note: One million metric tons of methane (1012g) equals 1.49 billion cubic meters of methane (52.6 billion cubic feet).
52
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A number of secondary coal producing countries are also of interest because although
they represented 23 percent of foreign mined coal tonnage in 1987, they accounted for only an
estimated 5 percent (2 to 3 million metric tons) of worldwide methane emissions. For the most
part, methane emissions are low in these countries because almost 75 percent of the coal was
produced from surface mines which have low methane emission rates. By comparison, surface
mining in the primary coal producing countries accounted for less than half of the total
production in 1987.
Methane emissions associated with coal mining in some of these secondary coal
producing countries could increase in the future, however. Many of the secondary coal
producers are developing nations that rely heavily on their coal resources for energy and export
revenues. As shallow coal reserves are exhausted, these countries will begin developing their
deeper coal resources, which will lead to increases in future methane emissions.
The remaining coal producing countries of the world account for less than 2 percent (0.6
to 1 million metric tons) of the estimated worldwide methane emissions from coal mining and only
5 percent of total coal production.41 As with the secondary coal producing countries, surface
mined coal accounts for 82 percent of the total coal produced in these countries. Future coal
production in these countries is also expected to be from the deeper coal reserves, however, as
shallow seams are depleted, which could result in increased methane emissions in the future.
Global Estimates of Methane Emissions from Coal Mining
As shown in Exhibit 3-10, coal mining and utilization operations throughout the world
emitted an estimated 33 to 64 million metric tons of methane to the atmosphere in 1987.42
41 The remaining coal producing countries include: Afghanistan, Albania, Argentina, Austria, Botswana,
Bulgaria, Burma, Chile, Ecuador, Egypt, Greece, Hungary, Indonesia, Iran, Ireland, Italy, Mongolia, Morocco,
Mozambique, New Zealand, Nigeria, Pakistan, Peru, Philippines, Portugal, Romania, Swaziland, Taiwan, Thailand,
Venezuela, Vietnam, Zaire, and Zambia.
42 Since one million metric tons of methane has a volume of 1.49 x 109 cubic meters at standard temperature
and pressure, it is estimated that between 44 and 96 billion cubic meters (2 to 3 trillion cubic feet) of methane was
vented to the atmosphere as a result of coal mining in 1987.
53
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China was the single largest source of methane emissions from coal mining related activities,
contributing an estimated 11 to 22 million metric tons, or just under 34 percent of the total
worldwide emissions. The Soviet Union was the second largest source of methane from coal
mining, with estimated emissions of 6 to 11 million metric tons, or almost 18 percent of the total.
The United States was third, accounting for 15 percent (5 to 9 million metric tons) of estimated
emissions. Together, these three countries were responsible for two-thirds (an estimated 22 to
42 million metric tons) of the total coal-related methane emissions.
In the future, it is expected that methane emissions associated with coal mining will
increase. Worldwide coal production is expected to increase, especially in developing nations.
During the 1980's, coal production grew by 2.7 percent per year, and this rate of growth is
expected to continue in the future as energy consumption increases in many developing
countries. This increase in production is expected to result in the mining of deeper coals which
tend to have higher methane contents and higher associated methane emissions.
A very approximate estimate of how much methane emissions from coal mining might
increase is shown in Exhibit 3-11. As the exhibit shows, by the year 2000 methane emissions
from coal mining could range from 72 to 81 million metric tons.
The methane emissions estimates developed in this study are compared to other
estimates in Exhibit 3-12. As the exhibit shows, previous estimates have ranged from 8 to 45
million metric tons per year, while the present study estimates emissions of 33 to 64 million metric
tons per year. The variation between estimates is largely attributable to differences in
methodology and input data, especially in terms of coal production, coal type and estimated
average methane emissions from the mined coal. Some of the major studies are described
briefly below and compared with the present study.
54
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EXHIBIT 3-11
ESTIMATED GLOBAL FUTURE METHANE EMISSIONS
FROM COAL MINING AND UTILIZATION
Estimated Coal Mining-Related
Methane Emissions. Million Metric Tons
Estimated Methane Emissions in 1987 47
Additional Methane Emissions in 2000
Associated with an Increase in
Global Coal Production
(@ 2.68% per year )* 19
Additional Methane Emissions in 2000
Associated with an Increase in Mine Depth
(from current 53% underground
to 60 to 70% underground)** 6 to 15
Total 72 to 81
This assumes that world coal production grows by 2.7 percent annually between 1990
and 2000, as assumed in IEA Coal Production 1987, which may be conservative in certain
countries. The Soviet Union and China, for example, are planning to expand coal
production at faster rates.
Increases in mine depth estimated from rates of change in mining depth since 1960 as
reported by IEA Annual Coal Production reports.
Koyama is credited with preparing the first estimate of methane emissions from coal
mining, in which he estimated that 20 million metric tons of methane was liberated annually as
a result of mining.43 His estimate was based on coal production data from 1960, however, and
coal production has increased by more than 75 percent between 1960 and 1987. In addition,
it appears that this estimate only included methane emissions from hard coal production.44
Given these two factors, Koyama's estimate likely underestimates current methane emissions
from coal mining.
43 Koyama, T., 1964.
44 World coal production Is generally divided between hard coal (bituminous and anthracite) and brown coal
(sub-bituminous and lignite). For this study, it was assumed that hard coal production represents underground
mines and brown coal production represents surface mines.
55
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EXHIBIT 3-12
COMPARISON OF COAL MINING-RELATED EMISSION ESTIMATES
Koyama (1964)
Hitchcock and Wechsler (1972)
Ehhalt (1974)
Seller (1984)
Crutzen (1987)
Seeliger and Zimmermeyer (1989)
Cicerone and Oremland (1989)
Present Study
20
8-28
8-28
30
34
24
25-45
33-64
17.7
5 - 17.7
5 - 17.7
17.7
18- 19
14
N/A2
2.5 Surfac
Type of Coal Year of Coal
Included In Production
Emissions Estimate Data
Hard Coal only1
Hard and Brown Coal
Hard and Brown Coal
Hard Coal only1
Hard Coal only1
Hard Coal only1
Hard Coal Only1
Hard and Brown Coal
1960
1967
1967
1975
N/A2
1987
N/A2
1987
27.1 Underground
1 Report does not specify coal type used in estimating methane emissions. Coal tonnage values approximately match
hard coal production only.
2 Not Available - This parameter was not specified in the report.
Another estimate of methane emissions from coal mining was included in a 1972 study
by Hitchcock and Wechsler.45 This study used Koyama's assessment of methane contents of
coal and coal production data from 1967. Unlike the Koyama study, the Hitchcock and Wechsler
study included methane emissions from both hard coal and brown coal production. In addition,
the authors established a range of 5 to 17.7 cubic meters of methane emitted per ton of coal
mined. Given the lower total coal production, however, the Hitchcock and Wechsler study
estimate of 8 to 28 million metric tons of methane emissions from coal mining underestimates
current emission levels.
45
Hitchcock, D.R., and Wechsler, A.E., 1972.
56
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The Hitchcock and Wechsler study was followed in 1974 by another study on the
atmospheric cycle of methane prepared by Ehhalt.46 In Ehhalt's study, the estimate of methane
emissions from coal mining was based directly on the work of Hitchcock and Wechsler and thus
ranged from 8 to 28 million metric tons.
In 1984, Seller published a study that estimated methane emissions form coal mining at
30 million metric tons.47 Seller used the same ratio of methane emissions per ton of mined
coal as Koyama had established, but he used hard coal production data from 1975.
Crutzen estimated methane emissions at 34 million metric tons in his 1987 study.48 This
estimate was based on an estimated emission rate of 18 to 19 cubic meters of methane per ton
of coal mined. It is not clear which year of coal production data was used for this estimate, but
early 1980's hard coal production data appears to have been used.
More recently, Cicerone and Oremland published revised methane emission estimates of
25 to 45 million metric tons from coal mining.49 Cicerone and Oremland did not develop new
data or a new methodology, but instead cited previous studies by Seller and Ehhalt. Thus, their
estimates are also based on the work of Koyama and, like the previous studies, include only hard
coal production data. It is not clear from their report what level of methane emissions per ton
of mined coal was assumed or what year's coal production data was used.
The most recent study reviewed herein was prepared by Seeliger and Zimmermeyer, who
estimated that global methane emissions from coal mining were 24 million metric tons in
1987.50 This estimate was based on hard coal production data from 1987 and assumed a
methane emission rate of 14 cubic meters per ton of coal mined. The combination of a low
assumed emission rate and only hard coal production data result in a significantly lower estimate
46 Ehhalt, D.H., 1974.
47 Seller, W., 1984.
48 Crutzen, P.J., 1987.
49 Cicerone, R.S., and Oremland, R.S., 1988.
50 Seeliger, W., and Zimmermeyer, G., 1989.
57
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than contained in the present study.
The present study estimates that methane emissions from coal mining could range from
33 to 64 million metric tons, which is higher than previous estimates. There are three main
reasons for the higher estimates:
Estimates use more recent coal production data, which reflects higher total coal
tonnage mined.
Estimates include both underground and surface mining. While it has been shown
that the methane content of surface mined coal is lower than underground mined
coal, the methane emissions associated with surface coal mining could be
significant because total surface coal production represents approximately 25
percent of total world coal production. Estimated methane emissions from surface
mining range from 3 to 5 million metric tons in this study, or account for about 8
percent of total emissions.
Estimates include methane emissions from coal mining, coal mine degasification
systems, and post-mining coal utilization. Emissions associated with
degasification systems and coal utilization are significant, accounting for
approximately 22 percent of total emissions.
Study Uncertainties
As has been previously indicated, a number of important assumptions were made in
developing these estimates of global methane emissions associated with coal mining and
utilization. As a result, the estimates should be considered approximate, and the uncertainties
associated with them are reflected in the ranges presented. Some of the major uncertainties and
their potential impacts on the emissions estimates are presented below.
Uncertainties in Data
Coal Production Data. As the discussion of methodology indicated, coal production
data is one of the foundations of any estimate of methane emissions from coal mining. In the
United States, coal production data are collected by both state and federal agencies and
accurate data on production levels by state and method (surface or underground) can be readily
58
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obtained. In many foreign countries, however, data are less available and their accuracy is less
certain. In addition, in some countries, data on coal production by type (hard or brown) is
available but the production method (surface or underground) is not. In these cases, it was
assumed that hard coal production represented underground mines and brown coal production
represented surface mines.
Naturally, these data limitations introduce uncertainties in the analysis. Without more
detailed information on the specific countries, however, it is impossible to determine the extent
to which these uncertainties affect the estimates herein. Where possible, foreign countries were
contacted directly for information on their coal production and this information was incorporated.
A more detailed examination of each country's coal production should be undertaken as part of
future research efforts.
Methane Content of Coal. The methane content of mined coal is the second critical type
of data. As with coal production data, good information exists for methane content in the United
States because of the work of the USBM, DOE, GRI, and others. In other countries, however,
these data are often unavailable. Such data are necessary on a country-by-country basis to
develop more accurate country-specific estimates of methane emissions from coal mining.
Uncertainties in Methodology
Mining Emissions Equation. The relationship between the in-situ methane content of the
mined coal and the methane emissions associated with mining as reflected in the "mining
emissions equation" is not well defined. The most accurate approach toward estimating these
emissions would be to develop an emissions factor for every coal mine. Such an approach
would be prohibitively expensive and data-intensive, however, given the number of mines
worldwide. Instead of taking this approach, a methane emissions equation was developed
statistically in this study. This equation was based on measurements at 59 United States coal
mines. The uncertainty in the equation was estimated to be +. 23 percent, based on the results
of the regression analysis, and this uncertainty estimate was used to develop a range of emission
estimates for each state, and for the United States average methane content estimates.
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Applying United States Data to Other Countries. The data required to develop a
methane emissions equation was unavailable for foreign countries, as was the in-situ methane
content data necessary to apply the mining emissions equation developed for the United States.
Thus, the estimated average methane emissions per ton of coal mined were determined for the
United States and applied to other coal producing countries. This assumption introduces
significant uncertainties into the results because it assumes that the mixture of coal mined in
each country resembles the mixture of United States coals (in terms of in-situ methane content),
that the mining methods used (underground longwall or room-and-pillar and surface) and the
proportion of each are similar, and that degasification technologies are applied to the same
extent. Since these and other factors vary, the accuracy of the assumption is uncertain. In the
absence of detailed country-specific data, however, it is difficult to produce international estimates
without making such assumptions. To reflect the uncertainty inherent in this assumption, an
additional range of +. 10 percent was applied to the range of average methane emissions
estimated for the United States
Uncertainties in Future Emissions Estimates. Finally, estimates of future emissions from
coal mining and utilization are highly uncertain and depend on factors such as future coal
production levels and the extent to which deeper coal mines are developed. For utmost
accuracy, such estimates should be determined on a country-specific basis, taking into account
forecasted growth in coal production, current and projected mining methods, and methane
content of future coal reserves. Such estimates were not prepared as part of this study, and
hence the estimates contained herein are approximate. The trend toward higher methane
emissions associated with coal mining is more certain, however, because of the established
relationship between methane emissions and coal productions levels.
60
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CHAPTER IV
Technical and Economic Evaluation of Methane Control Techniques
There are several options available for using the methane currently vented to the
atmosphere from coal mining operations. To date, these options have not been extensively
exploited in the United States, largely because of a variety of economic, institutional, and legal
barriers. While some mining operations in other countries, particularly in Europe and Australia,
collect and use the methane released during coal mining, this practice is still not widespread.
This chapter examines the technical and economic issues related to the application of
methane recovery and has two sections. The first section describes some of the major options
available for methane utilization and the major barriers currently precluding the application of the
recovery technologies in the United States. The second section provides a detailed economic
analysis of one utilization option - sale to a natural gas pipeline.
Options for Methane Utilization
Control of methane has long been essential in underground coal mines for safety reasons.
As discussed in Chapter 1 of this report, there has been significant research devoted to the
subject of methane control. The main technique for controlling methane remains ventilating the
underground mine workings. However, other supplemental methane control techniques have
been practiced for many years throughout the United States and around the world.
Modern methane control techniques produce gasses containing varying concentrations
of methane. Three primary types of gasses are produced by methane control techniques. The
first gas - Type 1 - is produced almost exclusively by a mine's ventilation system and contains
low concentrations of methane in air (generally less than 1 percent). The second gas - Type 2 -
- is produced by various degasification or methane drainage practices, and is an air-methane
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mixture with methane concentrations generally varying from 30 to 90 percent. The final gas -
Type 3 - is produced from certain degasification systems and generally contains 90 to 100
percent methane.
Currently, most of the methane produced by mining operations is vented to the
atmosphere. If this methane were used instead of vented, reduced emissions to the atmosphere
would be realized. The decision to use recovered methane is site-specific and depends on the
type of gas recovered. The principal uses for different gas types are described below.
Type 1 Gas - Type 1 gas is produced as a result of the mine's ventilation system and is
essentially air containing small quantities (generally less than 1 percent) of methane. This gas
is produced in large quantities by mines, often exceeding 40 million cubic meters (1.4 billion
cubic feet) per day and has always been vented directly into the atmosphere.51 Utilization
options for this Type 1 gas are limited, chiefly because of the low concentration of methane and
the large volume of gas. Two utilization schemes have been proposed for this gas: the first
involves removing the methane molecules from the gas stream, which results in a higher grade
energy source (up to 100 percent methane) and the second method uses the Type 1 gas as
primary input air for a combustion process utilizing oil, natural gas, or coal.
The removal of methane from the Type 1 gas can technically be achieved using various
molecular membranes or sieves.52 However, methane-air mixtures are generally difficult to
separate due to the similar separation characteristics of methane and nitrogen. In addition, the
systems usually require high inlet pressures, necessitating the compression of the Type 1 gas.
The power cost of such systems make them uneconomic at current gas prices. Moreover, the
process produces CO2 as a byproduct, which is also a greenhouse gas.
Alternatively, the Type 1 gas could be injected as air for a combustion process burning
coal, natural gas, or oil, such as those used for electric power generation, steel manufacturing,
or kiln heating. While this system readily consumes the methane in the combustion chamber,
51 Grau, R.H, 1987.
52 Garcia, F. and Cervik, J., 1988.
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the costs associated with transporting the large quantities of Type 1 gas any significant distance
would be very high. Thus, this process would only be suitable when the combustion process
plant was located near the mine's ventilation system discharge point. Given the amount of
methane released to the atmosphere from ventilation systems, additional research on this
utilization option should be undertaken.
Type 2 Gas - Type 2 gas is produced by methane control techniques that supplement
a mine's normal ventilation system. These techniques include 1) horizontal and cross measure
boreholes to pre-drain the methane in advance of mining, 2) cross measure boreholes and gob
(goaf) wells to drain the methane from sections of the mine where mining has been completed,
and 3) miscellaneous drainage systems, such as vacuum systems on sealed mine areas. The
methane produced by these processes can have varying methane concentrations, depending
upon such factors as the operating conditions of the system, the amount of air leakage into the
system, and local geologic and engineering conditions in the mine.
Utilization of the Type 2 gas is currently practiced at some mining operations. In some
operations, the methane is utilized as a low calorific value gas for industrial and home heating
purposes. In other cases the Type 2 gas is used as fuel in gas turbines to generate electric
power. The uses of for this gas are numerous and the higher calorific value, as compared to
Type 1 gas, often justifies its compression and transportation.
Type 3 Gas - Type 3 gas represents high quality, pipeline-grade natural gas and is
produced by 1) degasification systems similar to those producing Type 2 gas and 2) by
degasification systems that employ vertical wells drilled in advance of active mining operations.
Some mines with horizontal, cross measure, or gob wells have been successful in controlling the
operating conditions of these systems and have the required geologic and reservoir conditions
that enable them to produce pipeline-grade Type 3 gas. It must be emphasized, however, that
the optimum operating conditions for producing Type 3 gas may not be the optimum condition
for mine degasification. In these situations, mine safety cannot be compromised by the inefficient
operation of a degasification system for the purpose of producing Type 3 gas.
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The primary method of producing Type 3 gas is through the use of vertical wells drilled
in advance of the mine workings. This degasification system has the advantage of pre-draining
a gas that has not been contaminated by the mine air. The resulting Type 3 gas is usually of
pipeline grade, often requiring only dehydration and compression for utilization. Because of the
high calorific value, Type 3 gas can be utilized by many processes. Often it is compressed and
injected into natural gas pipelines for distribution to commercial and residential users. In
addition, it can be used for all of the same processes described above for Type 2 gas, such as
electric power generation or industrial heating.
In addition to the constraints placed on utilization by the various types of gas produced,
there remain, at least in the United States, certain legal and regulatory constraints that also affect
utilization of methane produced by coal mining. Unresolved issues of ownership of the methane
have negatively impacted the utilization of the produced methane (primarily in the form of Type
2 and 3 gasses). Further, the operation of mine ventilation and degasification systems is strictly
controlled by federal, state, and local regulatory bodies, which can affect the type and quantity
of produced gas. Detailed discussion of these constraints is beyond the scope of this report,
but further information can be found in other reports.53
Economic Evaluation of Methane Control Techniques
As described in the previous section, there are many uses for methane that is currently
vented into the atmosphere by the mining process. In many cases, however, the economic
attractiveness of these utilization options is not well defined. This section explains the
methodology developed to evaluate the economics of one utilization option - the sale of Type
3 methane produced by degasification systems into natural gas pipelines in the United States
The gas contained in coal is usually very similar to natural gas produced from
conventional gas reservoirs (sandstones, limestones, etc.) in that both generally contain 90 to
99 percent methane. Thus, this methane, can be sold for industrial or consumer use as natural
53 See for example, Counts, R.A., 1989; Eastern Mineral Law Foundation, 1988.
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gas if it is undiluted by mine air. The question addressed in this section is - under what
economic conditions and with which of the degasification techniques is it possible to recover a
high percentage of this methane economically? This section of the report examines three
degasification methods in terms of their methane recovery efficiency and their costs. For mines
that can sell recovered methane as natural gas, the study also examines the economic costs and
benefits of these degasification methods.
Methodology
The evaluation of control techniques for mining-related methane emissions followed a
four-step approach. This technical approach, including the data used and the models employed,
is summarized below. For more detailed information on the methodology and results, see
Appendix C.
1. Selection of Underground Mining Scenarios. Most U.S. underground coal mines
are located in the eastern United States. These eastern mines accounted for over 70 percent of
all United States underground coal mines and produced 240 million tons of coal in 1987. The
Warrior Basin and the Northern Appalachian Basin are two of the more active eastern United
States coal basins and were chosen as test settings for examining the economics of pipeline-
grade natural gas production using alternative methane recovery techniques.
The Mary Lee coal seam of the Warrior Basin, Alabama was selected to represent deep,
longwall mining operations that generate large quantities of methane emissions during mining.
Grau reports that 11 of the 15 highest methane emitting coal mines in the United States were
deep, longwall mines in Alabama and Virginia.54 The mining scenario modeled for the Warrior
Basin is a longwall mine in the gassy Mary Lee coal seam at a depth of 625 meters. The
selected coal and gas properties for the Warrior Basin, shown in Exhibit 4-1, reflect the geologic
conditions (i.e., mine depths, seam thicknesses, cleat spacings) currently encountered by some
active mining operations in this basin.
54 Grau, R.H., 1987.
65
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EXHIBIT 4-1
SUMMARY COAL AND GAS PROPERTIES FOR PRODUCTION MODELING
WARRIOR COAL BASIN
Coal Seam Identification
Coal/Gas Property Pratt Mary Lee Black Creek
Depth Below Surface(m) 396 625 663
Net Coal Seam Thickness (m) 4.3 2.65 2.87
Cleat Permeability (md) 20.4 7.30 6.1
Cleat Spacing (cm) 0.51 0.51 0.51
Matrix Porosity (%) 3.0 3.0 3.0
Initial Seam Pressure (kPa) 3,365 5,309 5,633
Seam Temperature (°K) 259 303 305
Initial Cleat Water Saturation (%) 100 100 100
Initial Matrix Gas Content (m3/gas per m3/coal) 15.6 20.4 20.9
Langmuir Volume (m3/gas per m3/coal) 18.8 24.4 25.2
Langmuir Pressure (kPa) 673 1,062 1,127
Desorption Pressure (kPa) 3,365 5,309 5,633
Desorption Time (Days) 10 10 10
Gas Gravity (Air = 1.0) 0.60 0.60 0.60
-------
Good geologic and reservoir data exist for the coal seams of this basin because of the active
coalbed methane production industry and the new mine degasification efforts currently
underway.55
The Pittsburgh coal seam of the Northern Appalachian Basin was selected as being
representative of the less gassy, moderate depth coal mines. Exhibit 4-2 presents representative
geologic and reservoir parameters for the Pittsburgh coal. Because this coal seam is one of the
most actively underground mined coal seam in the United States, a considerable amount of
research and data collection has been conducted by the USBM and DOE on this coal seam.56
2. Selection of Degasification Techniques. The primary technique for controlling
methane emissions in United States coal mines is the use of large volume air circulation to dilute
and sweep the methane out of the mine workings. Because ventilation leads to low
concentrations of methane within the vented air/methane mix, this control technique limits the
options available for utilization of the emitted methane. To produce methane in concentrations
that are acceptable for use as natural gas, the methane must be captured by specific
degasification methods. Three primary degasification methods are currently used in the United
States to capture methane before it is released into mine workings: pre-drainage vertical wells,
vertical gob wells, and horizontal wells. Data for capital costs, operating costs, and expected gas
production rates and quantities were assembled from numerous sources for each of the
techniques.57 In addition to evaluating these three primary degasification techniques
separately, the combination system of pre-drainage vertical wells and vertical gob wells was
evaluated. These four methane control techniques are discussed below.
55 See for example, Diamond, W.P., Bodden, W.R., Zuber, M.D., and Schraufnagel, R.A., 1989; Dixon, C.A.,
1989; McFall, K.S., Wicks, D.E., and Kuuskraa, V.A., 1986; and McElhiney, J.E., Koenig, R.A., and Schraufnagel,
R.A., 1989.
56 See for example, Diamond, W.P., Lascola, J.C., and Hyman, D.M., 1986; Mroz, T.H., Ryan, J.G., and Byrer,
C.W., 1983; and Deul, M. and Kim, A.Q., 1988.
57 Kuuskraa, V.A., Boyer, C.M., and McBane, R.A., 1989; Pothini, B.R., 1986; and Grau, R.H. and Baker, E.,
1987.
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EXHIBIT 4-2
SUMMARY COAL AND GAS PROPERTIES FOR PRODUCTION MODELING
NORTHERN APPALACHIAN COAL BASIN
Coal Seam Identification
Coal/Gas Property
Depth Below Surface(m)
Net Coal Seam Thickness (m)
Cleat Permeability (md)
Cleat Spacing (cm)
Matrix Porosity (%)
Initial Seam Pressure (kPa)
Seam Temperature (°K)
Initial Cleat Water Saturation (%)
Initial Matrix Gas Content (m3/gas per m3/coal)
Langmuir Volume (m3/gas per m3/coal)
Langmuir Pressure (kPa)
Desorption Pressure (kPa)
Desorption Time (Days)
Gas Gravity (Air = 1.0)
Waynesburg
107
1.22
50
0.64
2.0
772
288
100
4.4
16.0
1,896
772
100
0.65
Sewicklev
168
0.91
39
0.64
2.0
1,213
289
100
6.0
16.0
1,896
1,213
100
0.65
Redstone
213
0.76
32
0.64
2.0
1,544
290
100
6.0
16.0
1,896
1,544
100
0.65
Pittsburgh
Rider
243
0.30
30
0.65
2.0
1,813
291
100
7.2
16.0
1,896
1,813
100
0.65
Pittsburgh
244
2.44
30
0.64
2.0
1,813
291
100
7.2
16.0
1,896
1,813
100
0.65
en
oo
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Pre-drainage Vertical Wells - Pre-drainage vertical wells are similar to conventional oil
and gas wells which are drilled and operated from the surface. The wells are hydraulically
stimulated with large volumes of fluid (up to 380,000 liters) mixed with 22,500 - 27,000 kg of sand
under high pressure (up to 20,000 kPa). In this study, the wells were assumed to produce
methane from the mined coal seam as well as the other significant coal seams above or below
the main seam. In the Warrior Basin, the coal seams being multiply-completed by vertical wells
are the Pratt, the Mary Lee (the mined coal seam), and the Black Creek. In the Northern
Appalachian Basin, producing coal seams include the Waynesburg, the Sewickley, the Redstone,
the Pittsburgh Rider, and the Pittsburgh (the mined coal seam).
Vertical Gob Wells - Vertical gob wells produce gas from the collapsed zone created
after a longwall panel has been mined-out. Following the collapse of the coal seam roof, the
subsequent fracturing of the surrounding rock and coal strata allows the gob wells to produce
large quantities of methane in a short-period of time. After the initial surge of methane, the
quality of the gas may decline as it becomes mixed with air from the mine workings. However,
in some cases, the methane concentrations have been kept at 95 to 99 percent for long periods
of time (often over one year).58 For this evaluation, it was assumed that the modeled gob wells
could produce gas at pipeline quality for one year.
In-Mine Horizontal Wells - In-mine horizontal wells are drilled from within the active mine
workings into the unmined longwall panel. These wells, while reasonably effective in recovering
methane from the longwall panel in the main coal seam, are not able to capture methane emitted
from the overlying and/or underlying rock and coal strata. Also, because the mine workings need
to be well developed before the horizontal wells can be drilled, a significant amount of methane
is vented before these wells are fully installed. Horizontal well life was assumed to be 6 months
in this analysis, which is consistent with reported well lives from published sources.59
58 Dixon, C.A., 1989; Layne, A.W., Siriwardane, H.J., and Byrer, C.W., 1988.
59 Grau, R.H., and Baker, E., 1987; Pothini, B.R., 1986.
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3. Modeling of Methane Production. Methane production for these degasification
techniques was modeled using COMET-PC 3D, a finite-difference numerical production simulator
developed by ICF Resources with support from the Gas Research Institute.60 This simulation
model accounts for the storage and release of the adsorbed methane, estimates the diffusion-
based flow of the methane through the coal matrix, and calculates the two-phase flow of gas and
water through the coal cleat system. The specific coal and gas properties used to model
methane production from each of the coal mining regions were presented in Exhibits 4-1 and 4-2.
It is important to remember that these reservoir properties represent a hypothetical area within
the two mining regions, and should not be considered representative of either specific mines or
an average mine in these areas.
The longwall mining operations were modeled using a standard unit of comparison, a
longwall panel. Longwall panels in United States mines may range up to 3,000 meters in length
and will vary from 90 to 300 meters in width. For this study, a longwall panel 200 meters wide
by 1,540 meters long, with a 20 meter band of entry ways and pillars surrounding the longwall
panel, and incorporating a gob area defined by the overlying and underlying coal seams
presented in Exhibits 4-1 and 4-2, was used as the standard unit of comparison (38.6 hectares
or 95.5 acres). Although a longwall panel was selected as the unit of evaluation, the results of
this study can generally be applied to a similar sized area in a room and pillar mine, especially
when considering the pre-drainage effects of vertical wells and horizontal boreholes.
4. Economic Analysis. The first step in the economic analysis of each degasification
system was to estimate the capital and operating costs for installing the system. Then, the costs
and revenues were financially integrated to establish conditions under which the capture and sale
of the methane could be a profitable venture for the mine operator.
Capital and Operating Costs - The following Exhibits 4-3, 4-4, and 4-5, provide the main
cost components involved in the selected mine degasification program, as discussed further
below. These costs were compiled based on:
60 Kuuskraa, V.A., Boyer, C.M., and McBane, R.A., 1989.
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EXHIBIT 4-3
CAPITAL AND OPERATING COSTS
VERTICAL WELLS IN ADVANCE OF MINING
Cost (1988$)
Capital Cost Category
Surface Site Development and Preparation, Vertical Borehole
Drill, Complete, and Equip Well
Surface Production Equipment and Installation
Water Disposal Equipment
Hydraulic Fracture Treatment
Compressor
Abandon Well
Warrior
Coal
Basin
14,965/well
51,000/well
20,250/well
5,000/well
18,500/well
190/Mcf/d*
2,000/well
Northern
Appalachian
Coal Basin
12,185/well
32,000/well
14,000/well
5,000/well
18,500/well
190/Mcf/d*
2,000/well
Annual Operating Cost Category
Normal Operations and Maintenance
Water Disposal
Compressor Operation
6,635/welj
0.25/Barrel**
0.06/Mcf
4,950/well
0.25/Barrel
0.06/Mcf
Mcf/d -1,000 cubic feet per day (28.3 cubic meters per day).
Barrel - 42 United States gallons (160 liters).
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EXHIBIT 4-4
CAPITAL AND OPERATING COSTS
IN-MINE HORIZONTAL BOREHOLES IN ADVANCE OF MINING
Cost (1988$)
Capital Cost Category
Surface Site Development and Preparation, Vertical Borehole*
Drill, Complete, and Equip Vertical Borehole
Surface Production Equipment and Installation
Horizontal Well Drilling Equipment
In-Mine Methane Drainage Equipment and Installation
Drill, Complete, and Equip Horizontal Wells
Abandon Vertical Borehole
Compressor
Warrior
Coal
Basin
3,000/panel
10,125/panel
4,265/panel
295/panel
1,530/panel
4,650/panel
400/panel
190/Mcf/d**
Northern
Appalachian
Coal Basin
2,500/panel
6,400/panel
3,010/panel
295/panel
1,020/panel
4,515/panel
400/panel
190/Mcf/d
Annual Operating Cost Category
Normal Operations and Maintenance
Compressor Operation
1,330/panel
0.06/Mcf
990/panel
0.06/Mcf
Costs assume one vertical borehole serves five longwall panels or mine blocks.
Mcf/d -1,000 cubic feet per day (28.3 cubic meters per day).
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EXHIBIT 4-5
CAPITAL AND OPERATING COSTS
VERTICAL GOB WELLS DURING MINING
Cost M 988$)
Capital Cost Category
Surface Site Development and Preparation
Drill, Complete, and Equip Well
Surface Production Equipment and Installation
Abandon Well
Compressor
Warrior
Coal
Basin
14,965/well
76,125/well
21,325/well
2,000/well
190/Mcf/d*
Northern
Appalachian
Coal Basin
12,185/well
48,000/well
15,050/well
2,000/well
190/Mcf/d
Annual Operating Cost Category
Normal Operations and Maintenance
Compressor Operation
6,635/well
0.06/Mcf
4,950/well
0.06/Mcf
Mcf/d -1,000 cubic feet per day (28.3 cubic meters per day).
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(1) Surface Site Development and Preparation. This category includes the costs for
surface rights, surveying, site preparation, road construction, and installation of electric power.
(2) Drill, Complete, and Equip Vertical Wells. This cost category includes the costs for
the drilling and crew, well tubing and casing, and well cementing. It also includes the cost of
wellhead and downhole equipment such as pumps and motors. The variations in vertical well
costs reflect differences in well depths and any differences in the well equipment and completion
techniques required by each of the methane control techniques.
(3) Surface Production Equipment and Installation. Included in these costs are low- and
high-pressure gas separators, gas dehydration equipment, metering and pressure measurement
devices, and gathering lines for delivering the gas to a distribution pipeline. Also, flame arresters
and lightening protectors are included.
(4) Water Disposal Equipment. Because water production often accompanies pre-mining
gas recovery from coal seams, capital costs for water handling and disposal, such as for tanks,
gathering lines and disposal ponds are included.
(5) Hydraulic Fracture Treatment. These costs include manpower, materials, and service
costs for performing a single hydraulic stimulation of the target coal seam.
(6) Compressor. These costs are the pro-rated share of a compressor station servicing
a group of wells or boreholes.
(7) Abandon Well. Because the various well types have finite operating lives, this
category represents the cost of abandoning the well or borehole, as often required by state or
federal regulations.
(8) Horizontal Well Drilling Equipment. These costs represent the pro-rated share of the
capital cost associated with the purchase of the in-mine drilling equipment.
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(9) In-Mine Methane Drainage Equipment and Installation. These costs are associated
with the equipment placed in the mine to operate the horizontal boreholes.
(10) Drill, Complete, and Equip Horizontal Wells. This cost category represents labor and
material costs required for installing the horizontal boreholes.
(11) Normal Operations and Maintenance. These costs include the manpower, materials,
and power costs for the operation, maintenance, and administration of the producing wells.
(12) Water Disposal. A cost of $0.25 per barrel is used to account for the handling and
disposal of the produced water based on the field experience of large scale oil field operations.
Where the water meets surface discharge requirements, this cost could be considerably lower.
Alternatively, where the water needs to be trucked off-site for disposal, the costs may be several
times higher.
(13) Compressor Operation. Because the methane produced from degasification
operations is generally at very low pressures, (generally less than 25 psi), the gas pressure must
be boosted by compression. A cost of $0.06 per Met for operations and power is used, based
on current costs in the Warrior Basin.
Financial Analysis - In this study, the economic viability or benefit of methane emissions
control is established by calculating the difference between the revenues generated from the sale
of the produced gas and the costs incurred in producing and marketing the gas.61 As
previously mentioned, all underground coal mines require some form of methane emission
control. This is primarily through the use of mine ventilation systems. However, some mines
currently employ methane emission control techniques (vertical, gob, and horizontal wells) to
supplement the existing ventilation system. For those mines that have already installed methane
control systems and where the methane produced is of pipeline quality, the costs incurred in
producing and capturing the methane from these systems would only be the incremental costs
(above the already installed system cost) required to collect and transmit the produced gas.
61 Kuuskraa, V.A., Boyer, C.M., and McBane, R.A., 1989.
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These costs would include the compression facilities, gas collection system, and production
control systems. Therefore, this analysis, which assumes total investment cost (not incremental),
could be conservative when considering mines with existing methane control systems, assuming
pipeline quality gas can be produced by the mine's degasification systems.
To provide a present value basis for this calculation, the resulting profits or losses are
discounted using a 10% discount rate. The following equations are used:
Gas Revenues = Gas Production (Mcf) x Selling Price ($/Mcf)
NPV Profits/Losses ($/Mcf) = NPV of (Gas Revenues ($1 - Investment and Operating Costs ($))
Mcf of Methane Produced*
* Estimated methane recovery from standard longwall panel.
Revenues are calculated at wellhead gas selling prices ranging from $0.00/Mcf to $3.00/Mcf. The
zero gas selling price case assumes that no market exists for selling the gas (or that the
produced gas is not of pipeline quality) and that the methane is flared or vented. A $2.00 per
Mcf gas selling price (at the wellhead) reflects the near-term outlook for gas prices in the Warrior
and Appalachian Basins. The $3.00 per Mcf wellhead selling price represents a projected gas
price for the mid to late 1990's.
The economic effect of methane control on the mining operation is presented in terms of
the total net present value (NPV) profit (loss) per Mcf of methane produced. As a basis for
comparing the financial impact of methane control, the current average coal prices (mine mouth)
in the eastern United States range from $21 to $24 per ton.
Preliminary Economic Analysis Findings and Results
The analysis indicates that with good technology, substantial quantities of methane can
be recovered during mining operations and that, in certain cases, the mining company could
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realize substantial economic benefits. This section presents the findings and results from the
technical and economic analysis, first for a gassy, deep coal of the Warrior Basin and then for
the shallower coal of the Northern Appalachian Basin. Detailed results of the economic
evaluation can be found in Appendix C.
Significant reductions in methane emissions from coal mining can be achieved in the two
hypothetical study areas of Warrior and Northern Appalachian Basins using degasification ahead
of or in conjunction with mining. From the analysis performed, highly efficient methane recovery
can be obtained by using vertical wells installed ten years in advance of mining, gob wells
draining methane from the fractured gob area after mining, or a combination of the vertical/gob
well system. Horizontal wells, while effective for achieving short-term reductions in methane
emissions during mining, are the least efficient technique. This is because horizontal boreholes
only drain methane from the mined seam and do not affect the significant methane emissions
that stem from the coal seams and strata above and below the main mined seam.
Warrior Basin. The underground coal mines in the Warrior Basin are well documented
as being gassy. The mined coal seam and the adjacent coal seams may contain over 3 billion
cubic feet of methane gas in place per each longwall panel, most of which would be emitted
during subsequent mining operations.62 Because of this, many of the underground mines in
the Warrior Basin have adopted some form of methane drainage or degasification to supplement
the mine ventilation system. Also, because the methane produced by these degasification
systems is often of pipeline quality, two mine operators in the Warrior Basin are already collecting
and selling this methane as natural gas. A ready market exists for coalbed gas in this basin at
wellhead prices of $1.50 to $2.00 per Mcf.
The evaluation of the four methane control techniques indicated that from 18 to 60
percent of the methane that would otherwise be vented during the mining process could be
collected and utilized as natural gas (Exhibit 4-6 and Appendix Exhibits C-1 to C-9). In addition,
under near-term natural gas market conditions ($2.00 per Mcf wellhead sales price for methane),
these techniques can provide a net profit for the mining company.
62 Dixon, C.A., 1989.
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EXHIBIT 4-6
ECONOMIC ANALYSIS OF THREE OEGASIFICATON
SYSTEMS IN THE WARRIOR BASIN
Degasification Method
Net Present Value Profit (loss). $/Mcf
Methane
Recovery $0/Mcf** $2/Mcf** $3/Mcf**
59.8%
(0.71)
0.64
1.32
59.1%
48.1%
(0.47)
(1.05)
0.64
0.95
1.19
1.95
Vertical wells (10 year production)*
Vertical wells (5 year production)
and gob wells*
Gob wells*
* Four wells per longwall panel.
** Assumed gas selling price.
Vertical wells (including those that are later converted to gob wells) are the optimum
technique for reducing methane emissions from mining operations in the Warrior Basin. In
addition, this analysis also indicates that under current gas market conditions in the basin, the
recovery and sale of the methane (if maintained at pipeline quality) would result in a positive net
present value profit, thus benefiting the mining operation. Because of the economic
attractiveness of degasification practices (along with the positive impact on mining operations),
selected mining operations in the Warrior Basin are already recovering and selling methane that
would otherwise be vented.
Northern Appalachian Basin. The Northern Appalachian Basin is one of the major coal
producing areas of the United States. While large quantities of methane are emitted from the
underground mining operations, the amount of methane emitted per ton of coal mined is less
than that for the Warrior Basin. This is because the coal seams are shallower and contain less
methane, with a typical longwall panel containing less than 1 billion cubic feet of methane.
However, some mines must still rely on degasification systems to supplement the ventilation
systems. Although a substantial quantity of methane is recovery by these systems, no mines
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have yet to sell the recovered methane due to difficulty in maintaining pipeline quality, limited
economic benefit, restrictive natural gas and environmental regulations, and methane ownership
issues.
The evaluation of four methane control techniques indicated that from 16 to 62 percent
of the methane can be recovered (Exhibit 4-7 and Appendix Exhibits C-10 to C-18). Although
none of this produced methane is currently being recovered and sold in the Northern
Appalachian Basin, the analysis indicates that some of the methane recovery techniques could
be financially attractive under near-term natural gas market conditions. However, the quality,
regulatory, and legal barriers to the capture and sale of this gas must be overcome before mining
operations will undertake projects to recover and sell pipeline quality gas.
EXHIBIT 4-7
ECONOMIC ANALYSIS OF THREE DEGASIFICATION SYSTEMS
IN THE NORTHERN APPALACHIAN BASIN
Deqasification Method
Net Present Value Profit (loss). $/Mcf
Methane
Recovery $0/Mcf*** $2/Mcf*** $3/Mcf***
Vertical wells (5 year production)
and gob wells*
Vertical wells (5 year production)
and gob wells**
Gob wells*
62.4%
(1.36)
(0.19)
0.39
48.8%
44.1 %
(0.64)
(1.56)
0.49
0.44
1.05
1.44
* Four wells per longwall panel.
** Two wells per longwall panel.
*** Assumed gas selling price.
79
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The combination degasification system of using vertical wells that are later converted to
gob wells is technically most efficient for reducing methane emissions in the coal mines of the
Northern Appalachian Basin. However, unless this methane is recovered and sold, the net
present value of such projects are negative. Use of less densely drilled wells such as 2 vertical/2
gob wells, or only gob wells can lead to efficient methane capture and reduced costs to the coal
operation. Ultimately, degasification systems should be selected to maximize mine safety and
methane recovery.
In summary, this analysis indicates that current degasification practices, especially those
that utilize vertical wells drilled in advance of mining, can effectively recover methane that would
otherwise be vented in to the atmosphere by coal mining in the two areas studied. Under certain
conditions the produced methane can be sold profitably into the natural gas market by the
mining operator, as in the Warrior Basin. The economic attractiveness of methane recovery and
utilization depends on site-specific geologic, reservoir, and economic conditions. The
development of additional projects to produce and sell pipeline quality gas will also require the
resolution of institutional, regulatory, legal, and other barriers. If these additional problems are
resolved, however, this analysis indicates that the recovery of methane could be economic.
Other Benefits
Additional economic benefits, not addressed in this specific study, can accrue to a mine
operator from a mine degasification program. These benefits, while difficult to quantify, may
include improved safety for miners resulting from lower volumes of methane emitted into the mine
workings, lower ventilation costs, and improved coal production efficiency. One estimate from
a mine in the Warrior basin of Alabama indicated that without an active degasification program,
the mine would have required three additional ventilation shafts (at a cost of $15 million dollars)
and would have had to increase fan volume (at a cost of $250,000 per month).63
63 Dixon, C.A., 1989.
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Uncertainties in Methodology
As discussed earlier, the sale of Type 3 methane produced by degasification systems into
natural gas pipelines in the United States is one option for the utilization of methane recovered
during coal mining. The economic evaluation of this utilization option for the two study areas
was based on certain technical and economic assumptions. Some of the major uncertainties in
these assumptions and their impact on the evaluation are presented below:
1. Selection of Underground Mining Scenarios. The two mining scenarios selected
are representative of specific areas within the Warrior and Northern Appalachian Basins, which
have significant underground mining activity. However, the specific geologic, reservoir, and
mining conditions selected for the study are not representative of any specific mine nor are they
representative of the basin as a whole. They were selected to represent conditions that can be
found in both basins and therefore provide a first estimate of the potential for methane emission
reduction technology. To accurately assess the overall potential for methane emisison reduction,
a site-specific assessment of each mining operation would be required.
2. Selection of Degasification Techniques. The degasification techniques selected for
analysis represent those most commonly used in the United States. However, the actual
application of a system to a particular mining operation is not standard, but rather is site-specific
to the mining and geologic/reservoir conditions at the mine. For example, the number of wells
drilled, the spacing of the wells, and the length of time the wells are in operation are all unique
to each mining operation. The studied systems, with their combination of wells, represent only
some of the options available to mine operators. In addition, the ability of a mine to specifically
plan a degasification system many years in advance is often difficult, due to changing economic,
mining, and regulatory conditions.
3. Modeling of Methane Production. Estimating the methane production of the various
degasification systems was accomplished using a finite difference, numerical production
simulator, COMET PC 3-D, developed by ICF Resources under contract to the Gas Research
Institute. This simulator accurately estimates the production of the various coalbed methane
wells types, based on the geologic and reservoir data describing the coal seam and the
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engineering data describing the well. As with any numerical simulator, the more reliable the input
data, the better the quality of the resulting output.
4. Economic Analysis. The economic analysis assumed capital and operating costs
for the various degasification systems and the subsequent utilization potential for the produced
methane. The unique conditions of each mining operation preclude the use of the results as
being representative of all operations. Rather, the results are indicative of the scenarios studied
and provide a basis for determining the relative economics of other methane control techniques.
82
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Appendices
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Appendix A
International Workshop On Methane
Emissions From
Natural Gas Systems, Coal Mining
And Waste Management Systems
April 9-13, 1990
Washington, D.C.
Workshop Findings for Coal Mining
-------
Appendix A
International Workshop On Methane Emissions From
Natural Gas Systems, Coal Mining
And Waste Management Systems
Workshop Findings for Coal Mining
Emissions Estimates
1.1 Recent global studies of methane emissions from coal mining provide "order of
magnitude" estimates and identify those countries with the largest potential
opportunities for methane recovery. There are currently many uncertainties about
the absolute levels of emissions from this source, however, and about the
contributions of various countries to this total.
1.2 Coal mining activities are an important source of methane emissions on a global
scale. Current estimates generally suggest that coal mining activities emit about
30-50 million metric tons, although some estimates are as low as 20 million metric
tons and others are as high as 60 million metric tons. These emissions are
roughly 7 percent of global methane emissions and approximately 10 percent of
global anthropogenic methane emissions. However, since both the current
estimates and the methodologies which support them include many uncertainties,
more research is necessary to refine these estimates.
1.3 To meet the energy requirements associated with increased population and
additional development, coal production will likely increase from its current level
of about 5 billion tons. If coal production grows at the rate forecast by the
International Energy Agency, production levels could exceed 6 billion tons by
2000. In many countries, this increase in production will likely be accompanied
by an increase in the proportion of coal mined in underground mines and the
depth of these mines. This implies that methane emissions from coal mining
could increase by more than 25 percent over the next decade in many countries.
Steps to Improve Emission Estimates
2.1 More research is necessary to refine estimates of methane emissions from coal
mining activities.
One of the most important goals of future research will be to improve the
A-1
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methane emission factors that relate the methane content of the mined
coal to the amount of methane emitted from the mine. Among the
variables that should be investigated are: depth and rank of coal, geologic
and erosional conditions, mine type (underground or surface), mining
method (room and pillar or longwall), and age of mine.
Different models should be developed to approximate emissions in
different mining environments and in different coal basins and/or countries.
2.2 These estimates should be further refined by pursuing other research areas,
including: (1) improving the instrumentation and techniques used in measuring
methane emissions and in-situ gas content; (2) improving data quality (i.e., by
collecting better data on methane emissions through ventilation air and
degasification systems; (3) improving models for predicting emissions; (4)
assessing the relationship between mining practices and emissions; (5) refining
estimates of methane emissions from surface mining activities; and (6)
investigating emission levels from abandoned mines.
2.3 The methodology used in future studies of methane emissions from coal mining
should be clearly documented so that it can be verified by independent analysis.
Further, attempts should be made to standardize methane emission measurement
methods and estimation techniques to ensure that studies conducted by different
researchers are comparable. To this end, consideration should be given to
establishing a collaborative international data base on coal and mining
characteristics and methane emissions to facilitate the development of global
emission estimates.
2.4 To the extent financial resources are limited, future work should focus on those
countries where opportunities for recovering methane from coal mining are likely
to be large. These countries can be identified based on the "order of magnitude"
emission estimates in preliminary studies and based on industry information about
the relative gassiness of various coal mines.
2.5 Methane emissions during coal utilization should also be assessed and
opportunities for reducing these emissions explored as appropriate. While
methane emissions from large utility and industrial coal-fired boilers are low
(perhaps less than 10 ppm), it appears that emissions from domestic coal
combustion processes could be significant (perhaps on the order of 10-100 ppm).
Technical Potential for Reducing Emissions
3.1 Degasification technologies are used successfully in many countries to maintain
mine safety and enhance productivity in mines with high methane emission levels.
The benefits of using these technologies include increased safety, reduced
downtime, and reduced ventilation costs and capacity requirements.
A-2
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3.2 Current recovery operations at some mines in the United States and other
countries have reduced methane emissions to the atmosphere associated with
mining operations by 30-40 percent. The effectiveness of degasification
operations at these and other mines must be assessed on a site-specific basis
and will depend on many factors, including the methane content of the coal and
surrounding strata, the magnitude of the methane emissions, the type and age of
the mine, the time available for degasification, and geologic conditions at the site.
At some mines with high methane emissions, degasification systems might be
able to recover higher levels of methane, while at other mines the recovery
potential will not exist at all.
3.3 Most current degasification programs are not being undertaken because of the
methane recovery potential, but instead are essential to maintain mine safety.
Thus, the current experience with methane recovery might represent economically
attractive recovery levels, as opposed to the recovery levels that could be
technically achieved.
3.4 Additional benefits result from utilization of the recovered methane. These benefits
can include revenue or fuel cost savings from production of the gas and reduced
methane emissions to the atmosphere.
3.5 Strategies for using recovered methane should seek to minimize methane
emissions to the atmosphere. Many technologies are available to use methane
recovered during coal mining. Choices among these technologies depend on
methane production rates, gas quality, local energy markets and other factors.
3.6 In developing opportunities for using recovered methane, the safety of mining
operations cannot be compromised.
3.7 Many of the opportunities to make additional reductions are not justified on the
basis of current mining needs, gas market conditions and investment
considerations. Additional reductions may be justified on an environmental basis,
however, and the environmental benefits of additional recovery should be
examined further. If the value of reducing methane is incorporated into economic
assessments (i.e., through the provision of subsidies or low-interest loans) the
amount of economically attractive degasification would significantly increase.
3.8 Additional research and government funding is necessary to fully develop the
potential for using recovered methane. Work in the following areas is required:
Technologies that use medium-quality gas and small amounts of gas (from
small mines) should be given high priority in future research.
The recovery and use of methane from ventilation air can potentially be an
important source of methane reductions in the future, as appropriate
technologies are developed and demonstrated.
Research is necessary on the optimal integration of utilization technologies
A-3
-------
and mining operations in a manner that ensures mine safety and
maximizes gas recovery and use.
The interrelationship between coal mining, degasification, and methane
utilization should be explored.
Innovative ways of coupling mining operations with methane utilization
options should be developed and implemented.
Future efforts should emphasize assessing recovery potential, identifying
candidate sites and developing demonstration projects.
Policy Options for Reducing Emissions
4.1 Barriers to methane recovery and use - such as gas ownership, reasonable terms
of gas or electricity purchase, and competing environmental goals-should be
identified in various countries. Industry, government and environmental groups
should work together to remove barriers and to encourage the economic recovery
and use of methane from coal mining.
4.2 Government or other financial incentives that recognize the environmental value
of limiting methane emissions could greatly increase the level of methane
recovered and utilized by mining and other companies.
4.3 Financing will be needed to implement methane recovery systems in developing
and Eastern European nations, even for profitable projects.
4.4 International financing organizations should examine energy and environmental
policies and should consider the economic costs and benefits of mine
degasification and methane utilization, the environmental benefits of using gas
instead of venting it, and the opportunities for technology transfer, feasibility
studies, and demonstration projects.
A-4
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Appendix B
International Workshop On Methane
Emissions From
Natural Gas Systems, Coal Mining
And Waste Management Systems
April 9-13, 1990
Washington, D.C.
List of Attendees
-------
Appendix B
International Workshop On Methane Emissions From
Natural Gas Systems, Coal Mining
And Waste Management Systems
List of Attendees
Louis J. Aboud
American Gas Association
1515 Wilson Blvd.
Arlington, VA 22209
Tel: 703-841-8652
Fax: 703-841-8406
Dennis B. Amanda
Alphatania Group
St. Gennys
Pines Rd, Fleet
HantsGu138NL
England
Tel: 0252-615266
Fax: 0252-628378
Dilip Ahuja
The Bruce Co.
PM-221.EPA
Washington, DC 20460
Tel: 202-382-6935
Fax: 202-479-1009
Telex: 892758 EPA WSM
Riva Angelo
Snam S.P.A
R&D Division
PO Box 12060
20120Milano
Italy
Tel: (02)-5207934
Fax: (02)-52024435
Telex: 310246 EMI SNAM
David W. Barns
Senior Research Engineer
Pacific Northwest Laboratories
370 L'Enfant Promenadae, SW
Suite 900
Washington, DC 20024-2115
Tel: 202-646-5223
Fax: 202-646-5233
Sol Battino
c/o BMP Engineering
9 Dalman Place
Sylvania NSW 2224
Australia
Tel: 02-5228448
Fax: (Aust) 042-280893
B-1
-------
Lee Beck
Global Warming Control Branch
Global Emissions and Control Div.
U.S. Environmental Protection Agency
MD-63
Research Triangle Park, NC 27711
Tel: 919-541-0617
Jean Bogner
Argonne National Laboratory
Bldg. 362
9700 S. Cass Avenue
Argonne, IL 60439
Tel: 708-972-3359
Fax: 708-972-7288
Robert Berman
U.S. Department of Interior
Office of Policy Analysis - MS 4412
18th and C Streets, NW
Washington, DC 20240
Tel: 202-208-3751
Fax: 202-208-4867
A. D. Bhide
Scientist & Head, Solid Wastes Div.
National Environmental Eng. Research
Institute, Nemrumarg,
Nagpur- 440020
India
Tel: 26252-526071
Fax: 23893
Telex: 0712-233
Jacques Bodelle
Elf Aquitaine
Suite 500
1899 L Street, NW
Washington, DC 20036
Tel: 202-872-9581
Fax: 202-872-8201
Telex: 277566EXECUR
Charles M. Boyer II
ICF Resources
9300 Lee Highway
Fairfax, VA 22031
Tel: 703-934-3000
Fax: 703-691-3349
David Branand
National Coal Association
1130 17th St., NW
Washington, DC 20036
Tel: 202-463-2637
Fax: 202-463-6152
Wojciech Brochwicz-Lewinski
Ministry of Environment Protection, Natural
Resources and Forestry
Wawelska 52/54, 00-922
Warsaw, Poland
Tel: 253334
Telex: 812816
B-2
-------
Charles W. Byrer
U.S. Dept. of Energy
Morgantown Energy Technology Center
3610 Collins Ferry Road
Morgantown, WV 26507
Tel: 304-291-4547
Fax: 304-291-4469
Scott Bush
Center for Strategic & International Studies
1800 K Street, NW, Suite 400
Washington, DC 20006
Tel: 202-775-3295
202-775-3199
Darcy Campbell
Radian Corporation
PO Box 13000
Research Triangle Park, NC 27709
Tel: 919-541-9000
Francois Cagnon
Gas de France
361 Av. Pdt Wilson
BP33
93211 La Plaise St. Denis
France
Tel: (1) 49225206
Fax: (1)49225652
Telex: 236735F
Mark E. Casada
North Carolina State University
Bio and Ag Engineering Dept.
Box 7625
Raleigh, NC 24695-7625
Tel: 919-737-3121
Fax: 919-737-7760
Doris Ann Cash
Mine Safety and Health Admin
Dept of Labor
Technical Support
4015 Wilson Blvd. Rm 937
Arlington, VA 22202
Tel: 703-235-1590
FTS: 235-1590
Jeff Chandler
Jeff Chandler & Associates
PO Box 896
Elk Grove, CA 96759
Tel: 916-458-0126
Fax: 916-689-1968
Chai Wenling
Planning Dept., Ministry of Energy
137 Fuyou Street
Beijing 100031
China
Tel: 054131-470 or-430
Fax: 001 6077
Telex: 222866 MEDIC CN
S. Chattopadhya
The World Bank
Room #F 10.019
1818 H Street, NW
Washington, DC 20433
Tel: 202-477-6644
B-3
-------
Jason Ching
USEPA
AREAZ/ASMD (MD 80)
Research Triangle Park, NC 27711
Tel: 919-541-4801
Fax: 919-541-1379
Chris Collins
Eden Resources -
Environmental Consultants
8 Koromiko Road, Highbury
Wellington, New Zealand
Tel: 846-583
Fax: 846-583
R. Mike Cowgill
Pacific Gas & Electric Co.
R&D Department
3400 Crow Canyon Rd.
San Ramon, CA 94583
Tel: 415-866-5727 or
415-866-8107
Fax: 415-866-5318
Dr. David P. Greedy
British Coal Corporation
Headquarters Technical Dept.
Ashby Road; Stanhope-Bretby
Burton-on-Trent; Staffs; DE15 02D
England
Tel: (0)283-550500 ext. 31659
Telex: 341741 CBTD G
Andras Csethe
Mecseki Szenbanyak Pecs/Hung
PO Box 109
Pecs/Hungary, Sallai U. 48
Tel: 00-36-72-11523
Telex: 00-36-72-012242
Ken Darrow
Energy International, Inc.
127 Bellevue Way SE, Suite 200
Bellevue, WA 98004
Tel: 206-453-9595
Fax: 206-455-0981
Telex: 296751
Gokhan Dincel
Ministry of Energy and Natural Resources
Konyayolu, Bestepe
Ankara Turkey
Tel: 90-402136951
Fax: 90-4-2236984
Bettye F. Dixon
The Australian Gas Association
7 Moore St.
Canberra 2600
Australia
Tel: 61 62 473955
Fax: 61 62 497402
Telex: AA62137
Charles A. Dixon
Jim Walter Resources, Inc.
Route 1, Box 133
Brookwood, AL 35124
Tel: 205-556-6000
Salwa El Bussioni
Mine Safety and Health Admin.
4015 Wilson Blvd.
Arlington, VA 22203
Tel: 703-235-1915
B-4
-------
Sven-Olov Ericson
Vattenfall/UM
S-16287Vallingby
Sweden
Tel: +46 8 7397065
Fax: +468 374840
Telex: 19653 SVTELVXS
Ken Feldman
Office of Energy/USAID
SA-18, Room 508
Washington, DC 20523-1810
Tel: 202-875-4052
Fax: 202-875-4053
Bruce Findlay
Canadian Climate Centre
Environment Canada (AES)
4905 Dufferin Street
Downsview Ontario M3H5T4
Canada
Tel: 416-739-4330
Fax: 416-739-4380
Gerry Finfinger
U.S. Bureau of Mines
P.O. Box 18070
Cochrans Mill Road
Pittsburgh, PA 15236
Tel: 412-892-6550
Fax: 412-892-6614
Robert L. Frantz
Assoc. Dean for Continuing Education
and Industry Programs
Penn State University
126 Mineral Sciences Building
University Park, PA 16803
Tel: 814-865-7471
Fax: 814-865-3248
David Friedman
Interstate Natural Gas Assoc. of America
555 13th St., NW
Washington, DC 20004
Tel: 202-626-3234
Fax: 202-626-3239
Jerry Gardetta
Southern California Gas Co.
81 OS. Flower St.
Los Angeles, CA 90017
Tel: 213-689-3365
Fax: 213-689-17126
Michael J. Gibbs
ICF Incorporated
Suite 2400
10 Universal City Plaza
Universal City, CA 91608
Tel: 818-509-7186
Fax: 818-509-3925
B-5
-------
Roger Glickert
Energy Systems Associates
1130 17th Street, NW
Suite 520
Washington, DC 20036
Tel: 202-296-7961
John M. Goldsmith, Jr.
The New River Gas Company
921 Vicar Lane
Alexandria, VA 22303
Tel: 703-751-9258
Kjell Hagemark
Statoil
7004 Trondheim
Norway
Tel: 47-7-584248
Fax: 47-7-584618
Telex: 55278 STATD N
Ihor Havryluk
Geo Met Inc
2 Penn Center West
Suite 120
Pittsburgh, PA 15276
Tel: 412-788-4755
Nelson E. Hay
American Gas Association
1515 Wilson Blvd.
Arlinngton, VA 22209
Tel: 703-841-8475
Fax: 703-841-8406
Tetsuo Hayakawa
Waste Management Div.
Ministry of Health & Welfare, Japan
1-2-2, Kasumigaseki, Chiyoda
Tokyo, 100 Japan
Tel: 03-503-1711 ex 2474
Fax: 03-502-6879
Stephen Hirsfeld
GRCDA
8750 Georgia Ave.
Suite 140
Silver Spring, MD 20910
Tel: 301-585-2898
Fax: 301-589-7068
John Hoffman
U.S. EPA, ANR 445
401 M Street, SW
Washington, DC 20460
Tel: 202-382-4036
Fax: 202-382-6344
Kathleen Hogan
U.S. EPA, ANR 445
401 M Street, SW
Washington, DC 20460
Tel: 202-475-9304
Fax: 202-382-6344
John Homer
The World Bank
1818 H Street, NW
Washington, DC 20433
Tel: 202-477-1234
B-6
-------
Mangesh Hoskote
AID Office of Energy
Private Sector Energy Develop. Pro.
1611 N.Kent St.
Suite 200
Rosslyn, VA 22209
Tel: 703-524-4400
Fax: 703-524-3164
Julian W. Jones
USEPA
Air and Energy Engineering Research
Laboratory
Global Emission & Control Div.
(MD-62)
Research Triangle Park, NC 27911
Tel: 919-541-2489
Art Jaques
Environment - Canada
Place Vincent Massey
18th Floor
351 St. Joseph Blvd.
Ottawa, Ontario K1A OH3
Canada
Tel: 819-994-3098
Fax: 819-953-9542
Jia Yunzhen
Ministry of Energy (MOE)
137 Fuyou Street
Beijing, 10031
China
Tel: 054131-566
Fax: 0016077
Telex: 222866 MEDIC CN
Dr. Catherine A. Johnson
British Gas pic.
London Research Station
Michael Raod
Fulham, London, SW6 2AD
England
Tel: 01-736-3344
Mieczyslaw Kaczmarczyk
Polish Oil and Gas Company
Warsaw, Poland - 00.537
ul. Krucza 6/14
Tel: (004822)28-16-42
Fax: 29-08-56
Telex: 81 -34-66 pi
Bent Karll
Nordic Gas Technology Centre
Dr. Neergaards Vej 5A
DK-2970 Horsholm
Denmark
Tel: 4545766995
Fax: 454257 1644
James L Kelley
U.S. Dept. of Energy
PE-70, Rm 4G-036
1000 Independence Ave., SW
Washington, DC 20585
Tel: 202-586-8420
Fax: 202-586-2062
B-7
-------
Richard L Kerch
Consolidation Coal Co.
Consol Plaza
1800 Washington Rd.
Pittsburgh, PA 15241
Tel: 412-831-4527
Fax: 412-831-4916 or 4571
Telex: 247634
C. E. Kolb
Aerodyne Research, Inc.
45 Manning Road
Billerica, MA 01821
Tel: 508-663-9500
Fax: 508-663-4918
Daniel A. Lashof
Natural Resources Defense Council
1350 New York Ave., NW
Washington, DC 20005
Tel: 202-783-7800
Fax: 202-783-5917
Telex: 4900010562 (NRD U I)
Abbie W. Layne
US Dept. of Energy
Morgantown Energy Technology Center
3610 Collins Ferry Road
Morgantown, WV 26507
Tel: 304-291-4603
Fax: 304-291-4469
Adam Kotas
State Gelogical Institute Poland
ul. Bialego 1/11
41 -200 Sosnowiec, Poland
Tel: 663040
Telex: IGOG PL 0312295
Dina Kruger
U.S. EPA, ANR 445
401 M Street, SW
Washington, DC 20460
Tel: 202-245-3958
Fax: 202-382-6344
Velio Kuuskraa
ICF Resources
9300 Lee Highway
Fairfax, VA 22031
Tel: 703-934-3000
Fax: 703-691-3349
Robert Lott
Gas Research Institute
8600 W. Bryn Mawr
Chicago, IL 60631
Tel: 312-399-8302
Fax: 312-399-8170
Telex: 253812
Linda Lottman-Craigg
Seamgas/Geomet, Inc.
Rt. 1, Box 98C
Paeonian Springs, VA 22129
Tel: 703-777-0081
Fax: 703-771-4972
Leszek Lunarzewski
Lunagas Pty. Ltd
PO Box 222
The Junction
N.S.W. 2291
Australia
Tel: 61-49-296646
Fax: 61-49-296606
B-8
-------
Phil Malone
GeoMet and Seamgas
6200 Flintridge Rd.
Fairfield, AL 35064
Tel: 205-785-2913
Fax: 205-785-2937
Paul McNutt
Dept. of the Interior
Bureau of Land Management
18th and C Street, NW
Washington, DC 20240
Tel: 202-343-4780
Charles Masser
U.S. EPA
Energy, Air and Engineering
Research Lab MD62
Research Triangle Park, NC 27705
Tel: 919-541-7586
Fax: 919-541-2382
Dr. Denes Masszi
D. Masszi Consulting Services Ltd
35 Wynford Hts CRES Apt. 2605
Don Mills On M3C IK9
Canada
Tel: 416-444-4118
Fax: 416-444-4118
John Meyers
Washington International Energy Group
2300 N. Street, NW, Suite 600
Washington, DC 20037
Tel: 202-663-9046
Fax: 202-663-9047
Miao Fen
Professor/Senior Geologist
44, Yanta RD (N), Xian
Shaanxi Province, 710054
China
Tel: 029-714117 Ext. 337
Fax: 029-719357
Telex: 70037 CMECX CN
Greg Maxwell
Waste Management, Inc.
3003 Butterfield Road
Oak Brook, IL 60521
Tel: 708-572-2484
Fax: 708-620-0548
Susan Mayer
ICF Incorporated
9300 Lee Highway
Fairfax, VA 22301
Tel: 703-934-3782
Fax: 703-934-9740
Catherine Mitchell
Earth Resources Research
258 Pentonville Rd.
London N1 9JY
England
Tel: 01-278-3833
Fax: 01-278-0955
Tadahisa Miyasaka
Electric Power Development Co.
1825 K Street, NW, Suite 1205
Washington, DC 20006
Tel: 202-429-0670
Fax: 202-429-1660
B-9
-------
J. David Mobley
US EPA
Air and Energy Engineering Research Lab
MD-62
Research Triangle Park, NC 27711
Tel: 919-541-2612
Fax: 919-541-2382
Mark A. Moser
Resource Conservation Mgt., Inc.
PO Box 4715
Berkeley, CA 94704
Tel: 415-658-4466
Fax: 415-658-2729
John J. Mulhern
Mine Safety & Health Admin.
Dept. of Labor
Technical Support
4015 Wilson Blvd.
Arlington, VA 22202
Tel: 703-235-1590
Sidney O. Newman
U.S. Bureau of Mines
2401 E Street, NW
Washington, DC 20241
Tel: 202-634-9892
R. J. Nielen
Netherlands Organization for
Applied Scientific Research
TNO
Dept. of Environmental Technology
PO Box 342
7300 AH Apeldoarn
The Netherlands
Tel: 31 55493493
Fax: 31 55419837
Telex: 36395 tnoap nl
Shuzo Nishioka
National Institute for Environmental Studies
16-2, Onogawa, Tsukuba
305 Japan
Tel: 81-298-51-6111 ext. 309
Fax: 81-298-51-4732
Dr. Jurgen Orlich
Head of Hazardous Waste Div.
Federal Environmental Agency
Bismarck Platz 1
D-1000 Berlin 33
Fed. Rep. of Germany
Tel: 30-8903-2807
Telex: 183756UBAD
John G. Pacey
Emcon Associates
1921 Ringwood Ave.
San Jose, CA95131
Tel: 408-453-7300
B-10
-------
Joao Luiz Pereira-Pinto
Science & Technology Section
Brazilian Embassy
3006 Massachusetts Ave., NW
Washington, DC 20008
Tel: 202-745-2750
Fax: 202-745-2728
Peter J. Proudlock
CH(4) International Ltd.
808-48 Street, NE
Calgary, Alberta
Canada T2A 4L9
Tel: 403-273-6296
Fax: 403-273-6296
Clyde Perry
Washington Gas Light Company
6801 Industrial Rd.
Springfield, VA 22151
Tel: 703-750-4851
Fax: 703-750-7570
Gus Quiroz
Pacific Gas & Electric Co.
3400 Crow Canyon Rd.
San Ramon, CA 94583
Tel: 415-973-4813
Fax: 415-973-8147
Raymond C. Pilcher
Raven Ridge Resources Inc.
PO Box 55187
Grand Junction, CO 81505
Tel: 303-245-4088
Fax: 303-245-2514
Tad R. Potter
Pittsburgh Coalbed Methane Forum
Suite 201 Roosevelt Building
Pittsburgh, PA 15222
Tel: 412-391-6976
Fax: 412-391-7813
Mr. Robert Preusser
VP/Engineering and Gas Operations
Brooklin Union Gas
195 Montague Street
Brooklyn, NY 11201-3631
Tel: 718-403-2525
Fax: 718-522-4766
Howard Reiquam
Dr. Keith M. Richards
ETSU, Harwell Laboratories
Harwell
Didcot, Oxon, OX11 ORA
England
Tel: 0235433586
Fax: 0235432923
Telex: 83135
Mike Ryan
ICF Incorporated
409 12th Street, SW
Washington, DC 20024
Tel: 703-934-3698
Fax: 703-934-3590
L M. Safley, Jr.
North Carolina State University
NCSU, BAE
Box 7625
Raleigh, NC 27695-7625
Tel: 919-737-3121
Fax: 919-737-7760
B-11
-------
Peter W. Sage
British Coal Corporation
Coal Research Establishment
Stoke Orchard, Cheltenham
Gloucs. GL52 4RZ
England
Tel: England 242 67 3361
Fax: 242672429
Telex: 43568 (CBCRE G)
Dr. Aboud Saghafi
Australian Coal Industry
Research Laboratory
ACIRL, PO Box 9
Corrimal, N.S.W. 2518
Tel: (042) 841711
Fax: (042) 836001
Don Schellhardt
American Gas Association
1515 Wilson Boulevard
Arlington, VA 22209
Tel: 703-841-8464
Fax: 703-841-8406
Paul Shapiro
US EPA
RD-681
401 M Street, SW
Washington, DC 20460
Tel: 202-382-5747
Fax: 202-245-3861
Toufiq A. Siddiqi
Environment and Policy Institute
East-West Center
1777, East-West Rd.
Honolulu, HI 96848
Tel: 808-944-7233
Fax: 808-944-7970
Telex: 230-989-171
Hema J. Siriwardane
Professor, West Virginia University
College of Engineering
637 Engineering Science Bldg. WVU
Morgantown, WV 26506
Tel: 304-293-3192
Jeff Schwoebel
Resource Enterprises, Inc
400 Wakara Way
Salt Lake City, UT84108
Tel: 801-584-2436
Fax: 801-584-2424
Fred A. Skidmore, Jr.
Controlled Stimulation & Production, Inc.
3604 Wentwood
Dallas, Texas 75225
Tel: 214-361-4704 or
214-720-9850
Dr. Horst Selzer
Ludgwig Bolkow System Technik GmbH
Dimlerstr. 15
D-8012Ottobrun
West Germany
Tel: 089-60811026
Fax: 089-6099731
Lowell Smith
U.S. EPA
RD-682
401 M Street, SW
Washington, DC 20460
Tel: 202-382-5717
Fax: 202-382-6370
B-12
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Barry Solomon
US EPA
401 M Street, SW
PM221
Washington, DC 20460
Tel: 202-382-4334
Fax: 202-382-7883
Dr. Laszlo Somos
Hungarian Geological Institute
1022 Bimbo U. 9619
Tel: 36-1-1836912
Telex: 225220Mafih.
Nicholas A. Sundt
Office of Technology Assessment
600 Pennsylvania Avenue, SE
Washington, DC 20003
Tel: 202-544-4058
Bent R. Svensson
International Energy Agency
2 Rue Andre - Pascal
76775 Paris
France
Tel: 33-1-45249455
Fax: 31-1-45249988
Peet Soot, PhD
Northwest Fuel Development, Inc.
PO Box 25562
Portland, OR 97225
Tel: 503-297-6291
Fax: 503-297-1802
Kathleen Stephenson
The World Bank
1818 H Street, NW
Washington, DC 20433
Tel: 202-477-2770
Dr. David Streets
Argonne National Laboratory
EID/362
9700 South Cass Avenue
Argonne, IL 60439
Tel: 708-972-3448
Fax: 708972-3206
Prof. Robert J. Swart
RIVM
PO Box 1
372 BA Bilthoven
Netherlands
Tel: 31 30 743026
Fax: 31 30 250740
Telex: 47215 rivm nl.
Istvan Szucs
Mecsek Coal Mining Co.
7629 Pecs
Komjat, Hungary
Tel: 367225930
Fax: 367225880
Yasuo Takahashi
Climate Change Division
US EPA
7500 Woodmont Avenue, #S-602
Bethesda, MD20814
Tel: 301-907-9568
B-13
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Kazuhiko Takemoto
The World Bank
1818 H Street, NW
Washington, DC 20433
Tel: 202-477-4674
Fax: 202-477-6391
Telex: ITT 440098
Shiro Takenaka
Osaka Gas Co., Ltd.
New York Office
375 Park Avenue
Suite 2805
New York, NY 10152
Tel: 212-980-1666
Fax: 212-832-0946
Hideo Taki
Osaka Gas Co., Ltd
Corporate Planning Dept.
4-1-2, Hiranomachi, Chuo-ku
Osaka 541
Japan
Tel: 81-6-231-1748
Fax: 81-6-222-5831
Tang Hui Min
Chief Engineer
Jianshe Road, Tangshan,
Hebei Province
People's Republic, China
Tel: Tangshan 21458
Telex: 27207 CNTSKLY
Christian Tauziede
CERCHAR
BP2
60550 Verneuil en Halatee
France
Tel: 3344556677
Fax: 3344556699
Telex: 140094 F
Pramod C. Thakur, Ph.D.
Consolidation Coal Co.
Rt1, Box 119
Morgantown, WV 26505
Tel: 304-983-3207
Fax: 304-983-3209
Susan Thorneloe
US EPA
MD-62
Research Triangle Park, NC 27711
Tel: 919-541-2709
Fax: 919-541-2382
Basat H. Tilkicioglu
Pipeline Systems Inc.
460 N. Wiget Lane
Walnut Creek, CA 94598
Tel: 415-939-4420
Fax: 415-937-8875
Telex: 910-481-3601
Kyoji Tomita
Tokyo Gas Co., Ltd.
1 -5-20 Kaigan
Minato-ku, Tokyo 105
Japan
Tel: 011-81-3-433-2111
Fax: 011-81-3-437-9190
Telex: J-33663
B-14
-------
Lori Traweek
American Gas Association
1515 Wilson Blvd.
Arlington, VA 22209
Tel: 703-841-8453
Fax: 703-841-8406
Telex: 710-955-9848
John W. Warner
Amoco Corp.
PO Box 3092
580 West Lake Blvd.
Houston, TX 77253
Tel: 713-556-4259
Fax: 713-584-7556
Michael A. Trevits
U.S. Bureau of Mines
Pittsburgh Research Center
PO Box 18070
Pittsburgh, PA 15236
Tel: 412-892-6556
Fax: 412-892-6614
Dr. Ian A. Webster
UNOCAL Corp.
1201 West 5th Street
Suite MM-35
Los Angeles, CA 90051
Tel: 213-977-6382
Fax: 213-977-7064
W. Gregory Vogt
SCS Engineers
11260 Roger Bacon Drive
Reston, Virginia 22090
Tel: 703-471-6150
Fax: 703-471-6676
Hilmar von Schonfeldt
Island Creek Corporation
250 West Main Street
PO Box 11430
Lexington, KY 40575
Tel: 606-288-3595
Hubert Wank
Canadian Gas Research Institute
55 Scarsdale Road
Don Mills
Ontario, Canada 73B-2R3
Tel: 416-447-6465
Fax: 416-447-7067
D. J. Williams
CSIRO Div. Coal Technology
PO Box 136
N. Ryde, NSW 2113
Australia
Tel: 61-2-887-8666
Fax: 61-2-887-8909
Telex: AA25817
Jonathan Woodbury
ICF Consulting Associates, Inc.
10 Universal City Plaza
Suite 2400
Universal City, CA91608
Tel: 818-509-7157
Fax: 818-509-3925
B-15
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J. Remko Ybema Cathy Zoi
Netherlands Energy Research Foundation U.S. EPA, ANR 445
PO Box 1 401 M Street, SW
1755 26 Petten Washington, DC 20460
The Netherlands
Tel: 202-382-7750
Tel: 02246-4428 Fax: 202-382-6344
Fax: 02246-4347
Yuan Benhang
Head of Ventilating Dept. K.M.A./
Senior Mining Engineer
Xinhua Zhongdao Tangshan Hebei
People's Republic of China
Kailuan Mining Administration
Tel: Tangshan 23811 -2129
Hang Zhu
ICF Resources
9300 Lee Highway
Fairfax, VA 22031
Tel: 703-934-3000
Fax: 703-691 -3349
B-16
-------
Appendix C
Economic Evaluation of a Methane Control Technique
Detailed Analysis
-------
Appendix C
Economic Evaluation of a Methane Control Technique -
Detailed Analysis
As discussed in the second section of Chapter IV of this report, the economic analysis
of a coalbed methane utilization process must incorporate the technical capability of the process
with the financial costs/benefits of the process. This appendix details the results of the economic
analysis of the selected methane utilization option - the sale of the methane produced by
degasification systems into natural gas pipelines - for two coal mining areas in the United States.
Warrior Basin
1) Pre-Drainage Using Vertical Wells Completed in All Coal Seams - This methane
drainage technique consists of installing 1 to 4 vertical wells drilled from the surface into the
longwall panel to pre-drain the methane. Generally, the vertical wells would be completed in all
coal seams encountered by the well, including the main seam and the over or underlying coals.
Methane recovery efficiencies increase with the number of wells used per panel and with the
length of time these wells produce. The ICF Resources analysis shows that methane recovery
could vary from 8.7 percent of the methane gas in place (GIF) (1 well per panel, 5 years of
production) to nearly 60 percent of GIF (4 wells per panel, 10 years of production), Exhibit C-1.
The large scale methane drainage project at Oak Grove, Alabama, operated for twelve years at
25 acres per well spacing, and recovered about 70% of GIF (31 million cubic meters).64
The profits realized by a mining company employing the vertical well technique varies
depending on the selling price for the gas, the number of wells used, and the length of time the
project is operated. Where the degasification wells are drilled five years in advance of mining,
using four vertical wells per panel, the operator could capture 48 percent of the in-place methane
and achieve a NPV profit of $0.59 per ton coal mined, Exhibit C-2. If the degasification program
64 Diamond, W.P, Sodden, W.R., Zuber, M.D., and Schraufnagel, R.A., 1989.
C-1
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EXHIBIT C-1
SUMMARY OF COALBED METHANE PRODUCTION
PRE-DRAINAGE USING VERTICAL WELLS
COMPLETED IN ALL COAL SEAMS, WARRIOR BASIN
NPV Profit (Loss)
Number
of Wells
Well Spacing
(Acres/Well)
Cumulative
Methane Production
(MMcfl (% GIF)*
Vertical Wells Produced 5 Years
$0/Mcf**
$/Ton $/Mcf
$2/Mcf**
$/Ton $/Mcf
$3/Mcf**
$/Ton $/Mcf
1
2
4
95.5
47.8
23.9
240
746
1,324
8.7
27.1
48.1
(0.18) (1.13)
(0.38) (0.76)
(0.72) (0.81)
0.05
0.31
0.59
0.29
0.63
0.66
0.16
0.66
1.24
1.00
1.32
1.40
Vertical Wells Produced for 10 Years
1
2
4
95.5
47.8
23.9
471
1,128
1,646
17.1
41.0
59.8
(0.21)
(0.41)
(0.79)
(0.65)
(0.54)
(0.71)
0.15
0.51
0.71
0.48
0.67
0.64
0.33
0.97
1.45
1.05
1.28
1.32
* Total Gas in Place (GIP) for 95.5-Acre Mine Block is 2,751 MMcf.
** Assumed gas selling price.
o
rb
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is planned well in advance of mining (10 years), is intensely developed (4 wells per panel), and
the produced methane can be sold at the mine for $2.00 per Mcf, the operator could realize a
NPV profit of $0.71 per ton of coal mined while also capturing nearly 60 percent of the methane
in-place in all coal seams, Exhibit C-3. At higher gas prices of $3.00 per Mcf, the NPV profit
could reach $1.45 per ton of coal mined.
2) Drainage Using Vertical Gob Wells During Mining - Vertical gob wells capture the
methane present in the fractured gob area behind an advancing longwall face. Because of this,
recovery efficiencies are high and increase as the number of gob wells used increases. In the
Warrior Basin, it is estimated one gob well could capture 32 percent of the GIF while four gob
wells could capture up to 48 percent of the GIP, Exhibit C-4.
Because gob wells produce large volumes of methane in a very short period of time (1
year), the profits obtained from the sale of the methane can be substantial. The NPV profit for
this methane control technique is estimated to range from $0.71 to $0.84 per ton of coal mined
at a $2.00 per Mcf wellhead gas sales price, Exhibit C-5.
3) Pre-Drainage Using In-Mine Horizontal Boreholes - This methane drainage technique
is one of the most widely used in the mining industry, particularly in situations where methane
emissions exceed the capacity of the mine ventilation system. Most often, horizontal boreholes
are used for short-term methane emissions relief during mining. However, because methane
drainage only occurs from the mined coal seam, the recovery efficiencies of this technique would
be low, ranging from 10 to 18 percent, Exhibit C-6.
Because of the smaller quantities of methane produced, profits from the use of horizontal
boreholes would likely be lower than for the other degasification techniques, ranging from $0.21
to $0.35 per ton of mined coal, at $2.00 per Mcf gas sales price, Exhibit C-7.
4) Pre-Drainage Using Vertical Wells and Drainage Using Gob Wells - Efficient recovery
of methane could be achieved in a short period of time through the use of a combined
vertical/gob well degasification system. This involves drilling vertical wells in advance of mining
to drain the methane from the coal seam to be mined and then converting these wells into gob
C-4
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EXHIBIT C-4
SUMMARY OF COALBED METHANE PRODUCTION
DRAINAGE USING VERTICAL GOB WELLS DURING MINING, WARRIOR BASIN
NPV Profit (Loss)
Cumulative
Number Well Spacing Methane Production $0/Mcf** $2/Mcf** $3/Mcf**
of Wells (Acres/Well) (MMcfi (% GIF)* $/Ton $/Mcf $/Ton $/Mcf $/Ton $/Mcf
1 95.5 886 32.2 (0.47) (0.80) 0.71 1.20 1.30 2.20
2 47.8 1,117 40.6 (0.66) (0.88) 0.83 1.12 1.58 2.12
4 23.9 1,323 48.1 (0.93) (1.05) 0.84 0.95 1.73 1.95
* Total Gas In Place for 95.5-Acre Mine Block is 2,751 MMcf.
** Assumed gas selling price.
o
o>
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EXHIBIT C-6
SUMMARY OF COALBED METHANE PRODUCTION
PRE-DRAINAGE USING IN-MINE HORIZONTAL BOREHOLES
COMPLETED IN THE MARY LEE COAL SEAM, WARRIOR BASIN
NPV Profit (Loss)
Cumulative
Number Well Spacing Methane Production $0/Mcf** $2/Mcf** $3/Mcf**
of Wells (Acres/WelO (MMcfl (% GIF)* $/Ton $/Mcf $/Ton $/Mcf $/Ton $/Mcf
5 19.1 270 9.8 (0.15) (0.86) 0.21 1.14 0.39 2.14
10 9.6 397 14.4 (0.23) (0.88) 0.30 1.12 0.56 2.12
20 4.8 506 18.4 (0.33) (0.97) 0.35 1.03 0.69 2.03
* Total Gas In Place (GIP) for 95.5-Acre Mine Block is 2,751 MMcf.
** Assumed gas selling price.
o
CD
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EXHIBIT C-7
ECONOMIC BENEFITS OF USING HORIZONTAL BOREHOLES FOR
METHANE RECOVERY IN THE WARRIOR BASIN
I
UJ
UJ
tn
UJ
cc
Q.
In
2.00
1.50
1.00
0.50
-0.50
-1.00
20
10
$3/MCF
$2/MCF
$0/MCF
20 40
GAS RECOVERY EFFICIENCY, %
60
Prepared by: IGF Resources, 1990
o
CD
Number of wells per panel
Gas sales price at the wellhead
* * * Net Present Value does not incjude potential benefits to the mining operation (reduced ventilation requirements,
production increases, etc.) nor investment cost savings realized from already installed methane control systems.
-------
wells to drain the methane in the fractured gob area. Assuming 5 years of pre-drainage prior
to converting the vertical wells to gob wells, from 34 to 59 percent of the methane could be
captured, Exhibit C-8. The economics of this combined vertical/gob well degasification system
could be attractive. At a $2.00 per Mcf sales price, the NPV profit could range from $0.51 to
$0.69 per ton of mined coal depending on the number of vertical and gob wells drilled, Exhibit
C-9.
C-10
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EXHIBIT C-8
SUMMARY OF COALBED METHANE PRODUCTION
PRE-DRAINAGE USING VERTICAL WELLS COMPLETED IN THE MARY LEE COAL SEAM
AND DRAINAGE USING VERTICAL GOB WELLS DURING MINING, WARRIOR BASIN
NPV Profit (Loss)
Cumulative
Number Well Spacing Methane Production $0/Mcf*** $2/Mcf*** $3/Mcf***
of Wells* (Acres/Well) (MMcfl (% GIF)** $/Ton $/Mcf $/Ton $/Mcf $/Ton $/Mcf
1 1 933 33.9 (0.14) (0.23) 0.51 0.82 0.84 1.34
2 2 1,275 46.4 (0.32) (0.37) 0.59 0.69 1.05 1.23
4 4 1,627 59.1 (0.51) (0.47) 0.69 0.64 1.29 1.19
* Vertical Well Production for 5 years.
** Total Gas in Place (GIP) for 95.5-Acre Mine Block is 2,751 MMcf.
***
Assumed gas selling price.
o
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Northern Appalachian Basin
1) Pre-Drainaae Using Vertical Wells Completed in All Coal Seams - Because the reservoir
conditions of the Northern Appalachian coal seams are somewhat less favorable to pre-drainage
using vertical wells, a maximum methane recovery of 9 to 40 percent was estimated depending
on the number of wells drilled and the length of time these wells are produced, Exhibit C-10.
If market and regulatory conditions become favorable in the near-term in the Northern
Appalachian Basin, the $2/Mcf line on the following exhibits is the appropriate baseline.
However, if the mining company produces methane only for emissions relief in the mine and
does not sell the gas, as is the current situation in the basin, then the operation would be an
added cost ($0/Mcf line). The technically most efficient, although economically most costly
option, is a 10-year pre-drainage program using 4 wells per panel which could lead to recovery
of 40 percent of GIF. This program is estimated to cost, on an NPV basis, $0.30 per ton of coal
mined even with a wellhead gas price of $2 per Met This cost would increase to $0.67 per ton
of coal mined with no sale of the produced gas, Exhibits C-11 and C-12.
2) Drainage Using Vertical Gob Wells During Mining - Gob wells are an effective methane
drainage practice for the Northern Appalachian Basin, as evidenced by estimated methane
recoveries of 28 to 44 percent of GIF, Exhibit C-13.
Because of projected lower installation and operating costs, methane recovery with gob
wells in the Northern Appalachian Basin could be a moderate cost methane control technique,
when the produced methane is not sold. The NPV costs of using 1 to 4 gob wells would be
$0.18 to $0.45 per ton of mined coal, Exhibit C-14. If a market exists for the gas (at $2 per Mcf),
this technique becomes economically attractive with a projected NPV profit of $0.13 to $0.19 per
ton of coal mined.
C-13
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EXHIBITC-10
SUMMARY OF COALBED METHANE PRODUCTION
PRE-DRAINAGE USING VERTICAL WELLS
COMPLETED IN ALL COAL SEAMS, NORTHERN APPALACHIAN BASIN
NPV Profit (Loss)
Number
of Wells
Well Spacing
(Acres/Well)
Cumulative
Methane Production
(MMcf) (% GIR*
Vertical Wells Produced 5 Years
$0/Mcf**
$/Ton $/Mcf
$2/Mcf**
$/Ton $/Mcf
$3/Mcf**
$/Ton $/Mcf
1
2
4
95.5
47.8
23.9
78
205
321
8.7
22.9
35.9
(0.16) (2.83)
(0.32) (2.15)
(0.62) (2.66)
(0.08) (1.41)
(0.11) (0.75)
(0.28) (1.18)
(0.04) (0.71)
(0.01) (0.06)
(0.10) (0.44)
Vertical Wells Produced for 10 Years
1
2
4
95.5
47.8
23.9
141
296
355
15.7
33.1
39.7
(0.17) (1.68)
(0.34) (1 .59)
(0.67) (2.60)
(0.05) (0.51)
(0.07) (0.35)
(0.30) (1.17)
0.01 0.07
0.06 0.27
(0.12) (0.46)
Total Gas in Place (GIP) for 95.5-Acre Mine Block is 895 MMcf.
f Assumed gas selling price.
o
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EXHIBIT C-12
ECONOMIC BENEFITS OF USING VERTICAL WELLS FOR
METHANE RECOVERY IN THE NORTHERN APPALACHIAN BASIN
<*
uf
UJ
UJ
oc
Q.
UJ
2.00
1.50
1.00
0.50
-0.50
-1.00
20
40
10-YEAR GAS RECOVERY EFFICIENCY, %
Number of wells per panel
60
Prepared by: IGF Resources, 1990
* *
9 " " Gas sales price at the wellhead
°* * * * Net Present Value does not incjude potential benefits to the mining operation (reduced ventilation requirements,
production increases, etc.) nor investment cost savings realized from already installed methane control systems.
F07031-6
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EXHIBIT C-13
SUMMARY OF COALBED METHANE PRODUCTION
DRAINAGE USING VERTICAL GOB WELLS DURING MINING,
NORTHERN APPALACHIAN BASIN
NPV Profit (Loss)
Number
of Wells
Well Spacing
(Acres/Well)
Cumulative
Methane Production
(MMcf) (% GIF)*
$0/Mcf**
$/Ton $/Mcf
$2/Mcf**
$/Ton $/Mcf
$3/Mcf**
$/Ton $/Mcf
1
2
4
95.5
47.8
23.9
247
322
395
27.6
36.0
44.1
(0.18) (1.01) 0.18 0.99 0.35 1.99
(0.28) (1.21) 0.19 0.79 0.42 1.79
(0.45) (1.56) 0.13 0.44 0.41 1.44
Total Gas In Place (GIP) for 95.5-Acre Mine Block is 895 MMcf.
' Assumed gas selling price.
o
-------
3) Pre-Drainaqe Using In-Mine Horizontal Boreholes - For the Northern Appalachian
Basin, recovery efficiencies associated with horizontal boreholes range from 16 to 20 percent of
GIF depending on the number of boreholes drilled into a panel, Exhibit C-15.
Use of horizontal boreholes in the Northern Appalachian Basin, while a relatively
inefficient technique for methane capture, would be the lowest cost option. The projected NPV
costs projected would be $0.12 to $0.19 per ton of coal mined, Exhibit C-16. Horizontal
boreholes could produce a net profit of $0.07 to $0.11 per ton of mined coal if the gas could be
sold for $2 per Mcf at the mine mouth.
4) Pre-Drainaqe Using Vertical Wells and Drainage Using Gob Wells - As was the case
for the Warrior Basin, the combined vertical/gob well degasification practice in the Northern
Appalachian Basin is a highly efficient short term technique for recovering methane from coal
mines. From 33 to 62 percent of the methane that would otherwise be emitted could be captured
depending on the number of vertical and gob wells used, as shown in Exhibit C-17.
This analysis shows that a 2 vertical/2 gob well system would be the relatively low cost
yet high recovery efficiency technique providing a projected methane recovery of nearly 50
percent at a cost of only $0.20 per ton of coal mined (no gas sold), Exhibit C-18. This is also
a profitable technique, if the gas could be sold at $2/Mcf at the wellhead, with a potential profit
of $0.15 per ton of coal mined.
C-19
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EXHIBIT C-15
SUMMARY OF COALBED METHANE PRODUCTION
PRE-DRAINAGE USING IN-MINE HORIZONTAL BOREHOLES
COMPLETED IN THE PITTSBURGH COAL SEAM, NORTHERN APPALACHIAN BASIN
NPV Profit (Loss)
Cumulative
Number Well Spacing Methane Production $0/Mcf** $2/Mcf** $3/Mcf**
of Wells (Acres/Well) (MMcfl (% GIF)* $/Ton $/Mcf $/Ton $/Mcf $/Ton $/Mcf
5 19.1 147 16.4 (0.12) (0.96) 0.11 1.04 0.22 2.04
10 9.6 170 19.0 (0.14) (1.11) 0.11 0.89 0.23 1.89
20 4.8 179 20.0 (0.19) (1.44) 0.07 0.56 0.20 1.56
* Total Gas In Place (GIP) for 95.5-Acre Mine Block is 895 MMcf.
** Assumed gas selling price.
o
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EXHIBIT C-17
SUMMARY OF COALBED METHANE PRODUCTION
PRE-DRAINAGE USING VERTICAL WELLS
COMPLETED IN THE PITTSBURGH COAL SEAM
AND DRAINAGE USING VERTICAL GOB WELLS DURING MINING,
NORTHERN APPALACHIAN BASIN
NPV Profit floss)
Cumulative
Number Well Spacing Methane Production $0/Mcf*** $2/Mcf*** $3/Mcf***
of Wells* (Acres/Well) (MMcfi f% GIF)** $/Ton $/Mcf $/Ton $/Mcf S/Ton $/Mcf
1 1 291 32.5
22 436 48.8
44 558 62.4
(0.09)
(0.20)
(0.55)
(0.44)
(0.64)
(1.36)
0.14
0.15
(0.08)
0.64
0.49
(0.19)
0.25
0.33
0.16
1.19
1.05
0.39
* Vertical Well Production for 5 years.
** Total Gas in Place (GIP) for 95.5-Acre Mine Block is 895 MMcf.
*** Assumed gas selling price.
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EXHIBIT C-18
ECONOMIC BENEFITS OF USING VERTICAL AND GOB WELLS
FOR METHANE RECOVERY IN THE NORTHERN APPALACHIAN BASIN
2.00
: LSD
Ť*
n
UJ
LU
UJ
DC
Q.
tL
1.00
0.50
-0.50
-1.00
. * *
o * *
& ***
0 20 40 60
5-YEAR VERTICAL/1-YEAR GOB GAS RECOVERY EFFICIENCY, %
Number of wells per panel Prepared by: ICF Resources, 1990
Gas sales price at the wellhead
Net Present Value does not include potential benefits to the mining operation (reduced ventilation requirements,
production increases, etc.) nor investment cost savings realized from already installed methane control systems.
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