AN INTRODUCTION TO
OPTIONS FOR
REDUCING METHANE
EMISSIONS FROM COAL
MINES
^formation Resources Center
US EPA (3404)
401 M Street S
Washington, DC 20u
METHANE
O U T R E A C H
> R O C RAM
IEPA
1430-
R-
93-006C
Takea from Chapter Four o£ Options for Reducing Methane Emissions baernationalfy.
Volume II: mtemational Opportunities for Reducing Methane Emissions; Report to Congress
EPA Document Number 430-R.-93-006" B
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COAL MINING
Background
Methane Production. Storage, and Emissions
Methane is produced during coaiification (the process of coal formation} and remains trapped
under pressure in the coal seam and surrounding rock strata. This trapped methane is
released during the mining process when the coal seam is fractured. Methane released in this
fashion will escape into the mine works, and will eventually be emitted into the atmosphere.
The production of methane during coaiification may exceed the adsorptive capacity of the
coat. For example, although the highest gas content measurements for U.S. anthracite ?oai
are only 21.6 cubic meters per metric ton. 180 cubic meters of methane may be produced
during coaiification (Diamond at al., 1986). As a result significant quantities of methane seep
into and are stored in the rock surrounding the coal seam.. This methane seeps back into the
mine working as the coal is mined. Mine air containing methane is removed from the mine
workings, and is generally vented directly into the atmosphere. • . . •
The quantity of methane emitted per tome of mined coat depends upon several characteristics
of the coal, the most important of which are: 1) gas content, 2) •permeability and gas
diffusion rates, and 3) method of mining. The gas content of coal depends upon its rank and
geological history. Coal rank is a measure of the degree of coaiification; as. coal rank
increases, the amount.of methane produced* also increases (see Exhibit 4-1). Furthermore,
higher ranks of coal have greater adsorptive capacities and win tend to contain more gas.
Because pressure increases with depth, deeper coal seams generaly contain more methane
than shallow coal seams of similar rank. Thus, deeper mines with coal of a higher rank will
typically contain larger quantities of methane.
Permeability and diffusion rates are also important because they determine how quickly gas
can migrate through the coal and into the mine workings. After coal is mined, the strata
overrying the mined coal are allowed to cave in, causing the formation of a rubbleized area,
termed a "gob." This fracturing increases the permeabifity of the methane-containing strata.
and facilitates the release of methane. Because more coal is removed during longwalt mining
and fewer otters-remain, the caving associated with tongwaU mining is generally more
extensive, and thtts methane released per tome of coal is generally higher with lohgwall
mining than with worn and piUar mining. .
Mamana Racovarv and Utilization StrataaJM .
Techniques for removing methane from underground mine workings have been developed
primarily for safety reasons, because methane is highly explosive in air concentrations
between 5 and 1S percent. These same techniques can be adapted to recover methane so
that the energy value of this fuel is not wasted. Where methane utilization is combined with
recovery, methane emissions into the atmosphere are reduced.
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COM. MINING
Important factors when considering options for reducing methane emissions from coal mining
are: the geologic and reservoir characteristics of the coal basin; mine conditions and mining
method; current mine gas recovery 'systems: potential gas quality and use options: and
technical and economic capabilities. In particular, the recovery method largely determines the
quality and quantity of gas recovered, which in turn determines the possible utilization
options. Developing uses for recovered methane is required if emission reductions are*to be
achieved. The sale and/or use of methane can offset the costs of recovery in certain cases.
Furthermore, improving methane recovery techniques can result in safer, more productive
mines, with lower ventilation costs (Dixon, 1987).
Exhibit 4-1
Coal Rank and Methane Production
YMd etton
1600 3200 4800
Co* Rank
Peal
Subbtturrtinous
Hi0h
Volatile
Bituminous
M«oWolatile)
Bituminous
Anthracite)
45
91 136
YMdmftton
181
Sotrea: USB»A. 1990.
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COAL MINING
Exhibit 4-2
Coal Mining and Methane Recovery Techniques
(a) Longwall Mining
(b) Roonvand-piilar Mining
(c) Vertical Gob Weil
(d) Vertical Degasfficatlon Well
(e) Cross Measure and
Horizontal Boreholes
(f) Surface Equipment
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-4
COAL MINING
Because the quality of gas that is recovered determines the possible gas utilization options,
each of the four techniques presented here is a complete project based on a particular
recovery method and its associated utilization options. Additionally, these strategies are
structured according to technological and economic criteria and overall applicability. The four
strategies presented are:
• Enhanced Gob Well Recovery;
* Pre-Mining Degasification;
• Ventilation Air Utilization; and
• Integrated Recovery.
Enhanced Gob Wei Recovery: This strategy recovers methane from the go*> area of a coal
mine - the highly fractured area of coal and rock that is created by the caving of the mine
roof after the coal is removed. Gob areas can release significant quantities of methane
into the mine, and if this gas is recovered before entering the mine, ventilation
requirements can be reduced (see Exhibit 4-2. Coal Mining and Methane Recovery
Techniques). Typically,,gob gas is diluted by mine air during-.productiat so a medium
quality gas is obtained (300-800 Btu/cf; 11 -29 MJ/m3). This type of gas can be used in
a variety of application, including on-site power generation, gas distribution systems, and
industrial heating. Enhanced gob wen recovery can involve ovmine arid/or surface wells:
using existing technology that is currently employed in many countries. In many cases,
the capital requirements for methane recovery are low compared to the Amount of gas that
may be produced. The capital cost associated with gas utilization can vary significantly,
being quite high for electricity generation, particularly where gas turbines are-used.
Pre Mtaing Degasification:. This strategy recovers methane, before coal is mined.
mining degasification can be attractive where geologic conditions ere appropriate because
the methane is removed before the air from the mine workings-c&nmixwithit.
degasification typically recovers a higher quality gas (900-1000 Btu/cf; 32-17 MJ/m*}
which can be used as a chemical feedstock in addition to bemg used for power generation
an-i industrial or residential applications. Pre-mining degasification can be an in-mine or
surface operation. • When done inside the mine, boreholes can be drilled anywhere from
six months to several years in advance of mining. Surface drBJed vertical well* can be
drilled anywhere from .2 to more than 10 years in advance of mining. Pre-mining
degasification requires more advanced technology and equipment than enhanced gob well
recovery, and therefore has higher capital costs.
Ventilation Air UtBzstfon: -Most mine gas is released to the atmosphere in the ventilatiofv
air used in the mine. Ventilation, necessary in underground coal mines for safety reasons,
is achieved with large fans which blow air through the mine. The recovery technology is
basic, but the operating costs of.running the fans can be high if the mine is gassy.- The
methane content of the vented air must be below 5. percent for safety reasons,, and is
frequently as low as 0.5 percent to comply with relevant regulations. In spite of its low
concentration, it appears that there may be opportunities to use ventilation air as
combustion .air in turbines or boilers (Granatstein et al.. 1991; 6SA. 1991). However, the
technical and economic feasibility has not yet been demonstrated.
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COAL MINING
Integrated Recovery: The most significant methane emission reductions are likely to occur
by employing a combination of methane recovery options, indeed, many US coal mines
currently use a combination of in-mine and surface recovery methods both before mining
and from gob areas (Soot. 1990). The technological and capital requirements of such
integrated systems are likely to be moderately high, but it is possible that the additional
opportunities for gas utilization, as well as the enhanced mine safety, could justify the
required investment.
Exhibit 4-3 summarizes information on these four coalbed methane recovery and utilization
strategies. The four strategies are described in more detail in the individual technological
assessments.
»
The assessments consist of the following sections:
•Recovery Technology Descriptions; -
• Utilization Technology Descriptions;
•Costs; • .
•Availability;. ...
•Applicability; ;
• Barriers; and
• Benefits.
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COAL MIMING
•' 2 . Enhanced Gob Well Recovery
Enhanced Gob Well Recovery is an approach that seeks to improve and augment methane
recovery techniques that are already in place at a mine so that recovery is more efficient. This
strategy builds on ,'ocal experience and methods of operation.
Gob areas consist o'f fractured rock and coal that have collapsed into mined-out areas. Since
these areas are considerably more permeable than intact coal and rock, methane stored above
and below the coal seam is released during and after the. creation of this gob area. The
proximity of the gob area to the lower pressure of the mine can result in the flow of
significant quantities of methane into the mine workings. This released methane is typically
emitted into the atmosphere, rather than being utilized.
In many deep coal mines, methane concentrations in the mine air cannot be maintained at safe
levels through ventilation alone without reducing coal production. Coal mine operators.seek
to maximize the amount of coal they can safely produce by employing additional methane
removal techniques 'to supplement ventilation. These systems are quite common; for
example, 100 state-owned underground mines in China. 18 Polish mates, at least 145 Russian
and Ukrainian mines, and about 35 U.S. mines use some type of advanced methane recovery
technique (JP International. 1990; Pilcher et al., 1991;Zabourdyeev, 1992,'USEPA, 1993aL
Mines in many other countries — including Czechoslovakia, Germany, Canada, the United
Kingdom, Japan, Australia, South Africa and India - also use these techniques.
The most common of these techniques are performed during mining operations (as opposed.
to ore-mining degasification), and include vertical gob wells drilled from the surface and
boreholes drilled from in-mine workings into gob areas. Enhanced Gob Wei Recovery-will
improve the efficiency of existing recovery systems and expand the use of these techniques.
Based on reported emissions data from a variety of countries, it appears that anywhere from
10 to 50 percent of the total methane emissions may be recovered with these technologies,
depending upon the site-specific geologic conditions, and the- design of the degasification
program. * .." . • ..
Recovery Technology Description
. • •
The two techniques described here are cross-measure boreholes and vertical gob wells. These
techniques are canted out in conjunction with active mining operations, and, as shown in
Figure 2. they recover gas from the caved-in or "gob" area. Removing methane fror.« the gob
area can be technically complex and must be integrated with mining operations. Because the
gob area is located within the mine and is surrounded by ventilated mine workings, medium-
quality gas is typically produced using these techniques.
In-Mine Boreholes: Boreholes have been used in coal mining since the 180O's. This
technology consists of drilling boreholes from the mine workings into unmined areas of the
coal seam and surrounding rock. Cross-measure boreholes, angled into the rock and coal
strata above and below the mine workings, are used to recover methane from the gob
areas. These boreholes are typically tens to hundreds of meters in length. The boreholes
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COAL MINING
are connected to an in-mine vacuum piping system, through which re-covered methane is
transported out of the mine (USEPA. 1990).
To maximize gas production the boreholes are operated under negative pressure, and in
the process mine air is drawn into the gob area and ultimately into the gas stream. The
quality of gas recovered will vary greatly depending on such factors as local geology, coal
rank, and the efficiency of the recovery system. Previous experience indicates that
medium quality gas (300-800 Btu/cf; 11-30 MJ/m3) will be recovered. Total methane
production will vary according to focal factors and the length of the borehole. Various
experiments in the U.S. have yielded production rates of'800 m3/day to 2,800 m3/day for
boreholes of 100 to 200 meters in length (Garcia and Cervik, 1985; Baker et al.. 1986).
Typically, 20 to 50 percent of the methane contained in the gob area may be recovered
through the use of in-mine boreholes (USEPA, 1990).
Japan and other countries practice a variant of this method of gob well recovery (Higuchi,
personal communication). When a longwall panel (typically 150*250 m wide and several
hundred meters long; 500-825 ft by 3000 ft) is completed, the resulting collapsed gob
area is sealed io reduce methane leakage into the mine workings. A steel pipe is inserted
into this sealed area and connected to an in-mine piping system enabling large quantities
of methane'to be recovered. • • •
» *
Vertical Gob WeBs: A second method of removing the methane from the gob area is to
drill vertical wells into the gob from the surface. Prior to mining, wetts am drilled to a point
2 to 15 vertical meters above the coal seam (USEPA, 1990). As the working face passes
under the well, the methane-charged coal and rock strata coOapse to form the gob. The
methane can be recovered under vacuum, rather than being released into the mine
workings. The main advantage of this technique is that it avoids the difficulties of
working in the mine., and possibly interfering with the mine operations. However, the use
of vertical gob wells requires relatively advanced drilling techniques and may be difficult
to integrate with multiple seam coal extraction.
Typically^ the gas quality is similar to that of the in-mine systems, although it may be
easier to. produce high quality methane using vertical goo. wells. As with in-mine
boreholes, surface gob wells can be operated under negative) pressure,.drawing mine.air
into the gob and diluting the recovered methane. Through careful monitoring of the gas
quality, and adjustment of the vacuum pressure, it is possible to maintain a higher and
more consistent gas quality (one company's mines in Alabama, U.S.. produce gas with
over 95 percent-methane from the gob wells) (Oixon, 1989). Over time, the quality will
decline as aw frdm the mine workings seeps into the gob area. Vertical gob wefts alone
may recover 30 to 4O percent of the methane contained 'm the gob area (USEPA, 1990).
Typical production figures are 2,800 m3 per day (100,000 cf). but are highly dependent
on site-specific factors (Baker at al.. 1988: USEPA, 1990). One mining operation in
Alabama. U.S.. recovers 849,000 m3 per day from 80 surface gob wells (Oixon. 1987).
The choice between in-mine and surface recovery techniques depends upon site-specific
factors that affect how cost-effective and appropriate these two techniques are for a
particular mine. These factors include mine depth, mining method, drilling costs, availability
of technology, surface activities, and terrain.
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COALlMlNING
Where the techniques described above are already in place, it is often possible to increase the
recovery efficiency and improve gas quality through improved drilling techniques, improved
pumping and in-mine "piping systems, and the use of more advanced monitoring and control
systems.
Drilling Techniques: Inappropriate drilling technology can slow the drilling of gob wells and
boreholes to the point where it is no longer feasible to implement these technologies.
However, adequate technology currently exists, and is in use in many countries. Where
improvements would be useful, those countries with oil and gas industries may be able to
adapt existing drilling capabilities; otherwise this technology must be imported, raising
project costs. Drilling improvements may include the use of diamond bits for rock, and
the capacity to drill bore holes with larger diameters and longer lengths.
* - .
tn-Mine Piping: In some mines, the overall quality of the in-mtne piping system can be
improved to reduce leakage. One important improvement is to ensure the integrity of *he
piping by installing safety devices to shut down the system in the event of mining
accidents. In some cases, increasing the capacity of the piping sy»terr will increase the
quantity of methane that can feasibly be recovered.
Pumping: Gas pumps with higher pressures and greater capacities increase the efficiency
of methane recovery. In general any improvements in retiabiKty and lifetime will be
beneficial.
Monitoring: The placement and spacing of boreholes and vertical wells is extremely
important for the effectiveness of a recovery program*. Monitoring the recovery system
in operation can also improve the efficiency of the system. Both of these important
factors involve relatively low-technology solutions. For example, each borehole can be
equipped with a shutoff device that activates when the gas qualify drops below 25
percent CH4. Many monitoring techniques are currently available and in use.
Utilization Technology D
on
There are four main options for utilizing medium quality gas: on-site power generation with
turbines, on-isite power generation with internal combustion engines, sale to a distribution
system, and industrial use in boilers. In each case, the sale or direct use of energy can often
justify the initial investment, in generating equipment. The anticipated gas flow rate and gas
quality (e.g., impurity levels and methane concentration) are particularly important in selecting
the appropriate, utilization option. . .
On-site Gas Turbines: Gas turbine systems can use medium quality gas to generate power
for on-site use or for sale to nearby electricity users or supply companies. Selection can
be made from among several gas turbine system -configurations, depending on factors
such as energy needs, technical capabilities, and capital availability.
Simple cycle gas turbine systems can operate with efficiencies ranging from 1 5 to 40
percent, increasing in efficiency as size increases (Williams and Larson, 1990). Combined
cycle turbine systems use the exhaust heat from a gas turbine to produce steam in a
boiler, which is then used to power a steam turbine. Alternatively, or in addition, waste
f
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MiNING
heat can be used for various local heating needs (i.e.. cc^generatiorti. When combined
with a heat recovery system, energy efficiencies can exceed 80 percent. Energy
efficiencies in the region of 50 percent can be achieved in combined cycle systems
without heat recovery.
Gas turbine systems have certain properties which make them a particularly attractive
utilization option for coal mines: 1) turbines come in a range of sizes, depending on the
required generating capacity; 2) the turbine combustion process is continuous, which
results in a high combustion efficiency and greater tolerance to deviations in fuel quality;
and 3) waste heat from the turbines can be used for industrial purposes, such as coai
•drying at the mine. Gas turbines usually require higher gas flows in order to bj
economical, and typical applications at coal mines would use one or more i to 5 MW
turbines (Sturgill. 1991). Gas turbines are running on medium quality mine gas in
Australia, China. Germany, and Japan.
On-site internal Combustion Engines: Internal combustion (1C) engines provide an
alternative method for burning medium quality mine gas for power generation. A
stationary engine can turn a generator which produces electric .energy, with operating
efficiencies ranging from 25 percent to 35 percent. With a heat recovery system, energy '
efficiencies can reach as high as 80 percent Williams and Larson, 1990). 1C engines are.
widely used to generate power from medium quality gas, and they tend to be better suited-
than turbines to low gas flows or irregular use. Although variations in methane
concentration previously caused some problems with the use of mine gas in 1C engines.
modem integrated control systems allow fluctuation:, in gas quality to be accommodated
in the operation in the engine {Pilcher et al.. 1991). 1C engines are available in sizes from
around 30 kW up to several MW. but are typically rated at several hundred kW.
Gas Distribution System: In developing countries, as well as some other regions, medium
quality mine gas can be distributed in residential and commercial gas supply networks and
used for cooking and heating. Many mines in China, for example), currently transport
medium quality methane short distances to residential consumers (JP International, 1990).
The system can be Very simple, consisting of pipes and rudimentary stoves which can
bum natural gas. High efficiency gas burners t.». use fuel more efficiently and will, also
reduce the emissions of uncombusted methane. Care should be taken in the construction
of new pipelines so that leakage is minimized. . .
•
in some countries, such as Poland, it may also be possible to distribute coalbed methane
in low-methane natural gas (LMNG) or coke-oven gas pipeline systems (Pilcher et al.,
1991). These medium quality gas pipelines are extremely attractive because theycan be
used to transport gas that would not otherwise be considered "pipeline quality," (e.g.,
pipeline quality gas must be 95 percent methane in the U.S.) In general, these types of
systems transport gas that is-50 to 70 percent methane.
Industrial Use: Medium quality gas may also be used as a combustion fuel for industrial
boilers. The gas can be supplied to nearby industries and used on its own or in
conjunction with other fuels in a boiler. Medium quality methane from coal mines is used
by local industries in several countries, including Czechoslovakia, Poland, and Ukraine.
The use of medium quality gas may require minimal conversion" of existing boiler
equipment, but in many cases requires no significant changes.
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COAL MINING
Cost;
Preliminary figures for the costs of recovery and utilization options are presented below. The
prices are U.S. figures and do not reflect the added cost of importing technology, lower labor
costs in developing countries, or other local factors. All costs are in U.S. dollars.
Recovery Costs: Recovery costs will vary depending on the recovery technique being
used and various site-specific factors such as mining depth and coal permeability. Per well
recovery costs are presented below for vertical gob recovery projects. The full costs
associated with hypothetical U.S. vertical gob well and cross-measure borehole projects
are also summarized. The costs are based on U.S. conditions and U.S. state*-of-the-art
technology. Simpler technologies may require less capital investment, but may also incur
larger operating costs. Furthermore, improvements in existing technology may be
significantly less expensive than indicated by the costs below.
• Vertical Gob Welis. Exhibit 4-4 summarizes the potential range of capita! costs on a
per well basis for vertical gob wells in various U.S. coal basins. The number of wells
drilled by a given mine will depend on site specific conditions. In addition, the capital
costs for vertical gob wells, vary between and within coal basins due to differences in
well depths (drilling costs), equipment costs, and costs for surface rights (which can
vary significantly on a site-specific basis depending on terrain and land use in the area).
Vertical gob wells are assumed to have fixed annual operating costs associated with
recovering - but not utilizing - methane. Recovery costs include all manpower,
materials, and power costs for the operations, maintenance,.and administration of
producing wells. The likely range of operating costs for vertical gob wells is $4,000
, to $8.000 per weir(ICF, 1992).
Project costs for hypothetical methane recovery projects using vertical gob. wells in
different U.S. coal basins have been estimated by the U.S. Bureau of Mines (Baker,
1988K These costs are for complete methane recovery projects associated with five
years of coal mining. Specific characteristics of the projects, such as the depth of the
wells, the number of welts per longwait panel, the rate of mining, and the productive
life of the wells, were assumed to vary by coal basin. Estimated project costs include
all planning, site development, equipment, drilling and subsequent operating costs, and
general overhead for each project. These costs include only the recovery portion of
the project.^Exhibit 4-5 summarizes the total costs of these hypothetical projects in
che selectedcoal basins (Baker, 1988). No gas production values are provided, so the
USBM study cannot be used to determine production costs on a 9/mcf basis.
Based on potential capital and operating costs, however, and with some assumptions
about gas production over the life of the wells, it is possible to make rough estimates
of methane recovery costs in terms of $/mcf. In general, the costs for vertical gob
well'recovery could range from a low of $0.50/mcf to levels of $3.00/mcf or higher.
Some U.S. vertical gob well projects have reported costs on the order of $0.75/mcf
to $1.00/mcf, not including the value of cost savings in the mining operations.
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Exhibit 4-4
Capital Costs for Gob Wells (per well costs)
Basin
Central
Appalachian
Northern
Appalachian
%
Illinois
Warrior
Western
Note: Capital costs .for go
preparation, and costs for
Sources used to develop r
Report of Investigations, 1
Low
$80.000
$60.000
$50.000
$90.000
$100,000
D wells include all costs for
drilling, completing and equ
anges: 1)USS»A 1990; 2)
4g* an* Crocs-Mraur* 80*
988K .
Medium
$130.000
$1 10.000
$100,000
$140,00
$150.000
High -
$190.000
$170,000
$1.60.000
$200.000
$210,000
surface drilling rights, site development and
ipping the wells.
CF Resources, 1 990b; 3) Baker. Garcia, and Cervik
•Ao* System* to Control Mtfftane in Goto (USBM
Exhibit 4-5
Total Vertical Gob Project Costs in Various U.S. Coal Basins
Location
Central Pannsylva tia
Northern West Virginia
Southern Virginia
Northern Alabama
Capital Cost
{*' milfions)
1.0
1.1
' 6.1
3.3
Operating Cost
($ minions)
0.3
0.3
0.2
0.5
Project Cost
($ miQons)
1.3
1.4
7.2
4.2
±
Note: Costs are undiseounted and represent trie sum of all costs incurred over the life of the project,
which was assumed to be five years and one year of development.
Source: Baker. 1988.
• gross-Measure Boreholes. In general, cross-measure borehole recovery projects will
have lower capital costs but higher operating costs than vertical gob-recovery, as a
result of the greater complexity of drilling within the mine. Cross-measure boreholes
are not a common degasification technique in the United States, although they are
widely used in other countries.
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.MINING
.13
No costs from actual U.S. cross-measure boreholes projects have been"published, in
general, costs for in-mine-piping systems will be similar to those for horizorUdl
boreholes, or about S5/foot of pipe (ICF Resources, 1990a). Drilling costs may be
tower than for horizontal boreholes, however, because the holes are shorter and less
powerful drilling equipment can be used. On the other hand, the shorter cross-measure
boreholes require proportionately more setup time and, because they are drilled through
hard strata rather than coal, could have slower penetration and higher drill bit wear
rates.
The U.S. Bureau of Mines has investigated the costs of hypothetical cross-measure
boreholes systems in four U.S. locations: central Pennsylvania, northern West Virginia,
southern Virginia, and northern Alabama (Baker, 1988). Costs for each area were
specific to anticipated local methane production rates and to local labor and material
costs. The US8M benefitted from some information provided to them by mining
operators in these regions. However, this study only estimated investment and
operating costs over a five-year period for a system with fixed methane capacity. No
estimate of actual production from the boreholes over time was provided. Therefore,
it is not possible to evaluate the economic viability of such a system using the USBM
costs alone. The results of the USBM analysis are summarized in Exhibit 4-6.
E*hibtt4-€ ,
Total Cross-Measure Borehole Project Costs in Various U.S. Coal Basins
Location
Central Pennsylvania
Northern West Virginia
Southern Virtfwar* '*.
Northern Alabama
Capital Cost
{* millions)
0.3
0.4
.- • 1.8
1.2
Operating Cost
{* mfflrans)
1.2
1.2
3.6 .
^ 1.5
Project Cost
(Smffiten)
1.5
1.6
5.4
2.8
Note: Costs are undiscounted and represent the sum of aH costs incurred over the life of the
project, which was assumed to be five years and one yeer of development.
Source: Bakerr-1988.
Utilization Costs: Utilization costs are presented for four options: power generation using
gas turbines; power generation using 1C engines; pipeline injection; and use in industrial
boilers. Trie costs are presented in U.S. dollars, based on U.S. applications and
technology. Costs in other countries could vary significantly depending on specific
conditions. . .
'* Power Generation in Turbines. The cost of using methane from coal mines in gas
turbines could range from $0.04/kwh to $0.07/kwh or higher. Key variables are the
size of the turbine, its efficiency, anci the market for waste heat. The cost of fuel
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14
COAL MINING
supplied to the turbine can also be an important cost item; where coal mine methane
is used, however, it is assumed that the only fuel costs are those associated with
transporting and preparing thg methane for use.
The equipment required for on-site power generation includes a turbine generator and
the gathering lines between the wellhead and the generator. For off -site sale of power
to a utility, transmission tine upgrades or an interconnection facility may be needed to
feed power generated at the mine into the main transmission line. A range of capital
costs for power generation are shown in Exhibit 4-7.
Exhibit 4-7
Capital Costs for Power Generation
Equipment
Gathering lines between ,
wellhead and generator
Gas Turbine1
Off-site Transmission2
Low
$10,000 per well
$800 per lew installed.
$100,000 per project
i Both 1C engines and gas turbines were examined in
assumed that a mine would prefer a gas turbine. &
profitable; 1C engine costs are not included here.
2 Off-site transmission costs are for costs of an int
costs assuma that an interconnection facility wouk
minimal*
Sources used to develop ranges: 1) Cart SturgUI P
(Prepared for USEPA April. 1991); 2} •Opportunities f
Coal Mining' (Draft Report Prepared for USEPA by 1CF
'Commercial Landfill Gas Recovery Operation: Techra
ami Wastes Xll (Institute of Gas Technology, 1 990); 4
Medium
$25,000 per wett
$1.000 per kw installed
$300,000 per project
the analysis. However, for
nee projects less than 4 M
^connection facility •and/or
1 not be needed and that
bww Gtntotion: 0»-srt» <
' Resources. 1990al; 3) Brtl
jlogy and Economics* in Kit
High
*40.000 per well
$ 1,200 per kw installed
$500,000 per project
cize* above 4 MW, it was
W were not shown to be
line up-grades. The low
line up-grades would be
h» and Safe to Utilities
(ethane Recovered During
Wolf e and Greg MaxweH,
ISS#. fiWJpy »*Ofll 0MWI9SS
Power Generation in iC Engines. The cost of generating power using 1C engine* is
likely to be slightly lower than for turbines, tn general, the capital costs of 1C engines
are lower, with estimates ranging from $350 to $ SCO per kilowatt (Soot. 1991;
Anderson, 1991). Operation and maintenance costs are generally higher than for
turbines, however, typically around $0.02/kwh. . .
1C engines are best $-.
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COAL
commercial pipeline. Capital and operating costs for
discussed below, based on U.S. experience.
The capital costs for gathering lines, compression, and
recovered gas are summarized in Exhibit 4-8. As the
components capital costs are presented in terms of the
gas production will determine the size of these
«
°f these comP°"ents are
** treatmen< of the
? H° WS- ** °ertain SystfilT1
b6Cause
for
Equipment
Gathering lines
between wellhead and
Central Compressor
Compressor(s)
Processing/Treatment
Between
Low
$10,000 per well
$7 80 per mcf/dav
per mcf/day
Medium
$45,000 per well
S190 per mcf/dav-
$20 per mcf/dav
$100,000 per well
$200 per mcf/dav
$30 per mcf/dav
Note: Capital costs for compressor and processing/treatment are based on maximum gas production per
day. Equipment costs for enrichment of gob gas are included in the total »/mcf operating costs.
Sources used to develop ranges: 1) USEPA 1990; 2» A Technical and economic Assessment of Methane
Recovery from Coat Seams (Prepared for USEPA by ICF Resources Inc., 1990b); 31 The Potential Recovery
of Methane from Coal Mining for Use in the U.S. Natural Gas System (Prepared by ICF Resources, Inc. for
USEPA, 1990); 4} W.W. Syfces 'Gathering Systems Concepts-Planning, Design and Construction'
Proceedings of the 1983 Coafoed Methane Symposmrr "*» University of Alabama at Tuscatoosa); Warren
ft. True 'Pipeline Economics* OH 9 Gas Journal Soedai... «»..*— 26. 19901.
In addition to capital costs, there will also be operating costs associated with
compression and processing, as shown in Exhibit 4-9. These operating costs are
based on aanual gas production.
•™ '
The capital costs for the gas pipelines that transport gas from the point of compression
to the commercial pipeline are presented in terms of their cost per mile. .Costs will
vary between or within -cgal basins depending primarily on terrain and land use
patterns. Exhibit 4-10 presents a range of costs, which reflects pipeline construction
experience in several U.S. coal basins. . '.
Finally, in some countries or at some mines it may be necessary to enrich gob gas
before it can be injected into pipelines. This will be the case in situations where
medium quality pipelines do not exist and where the mine cannot maintain pipeline
quality gas through monitoring and management of the gob recovery system.
Enrichment costs are quite uncertain and there has been limited experience with the
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Cc*i. MINING
. Exhibit 4-9
Operating Costs for Pipeline Injection
All Equipment Needed Between the Wellhead and a Central Compressor
Equipment
Compressor(s)
Processing/Treatment
Low
$.06 per mcf
$.02 per mcf
Medium
$.07 per mcf
9.03 per mcf
High
$.08 per mcf
$.04 per mcf
Sources used to develoo ranges: 1 ) ICF Resources 1990a; 2) Warren R. True 'Pipeline Economies' 0.'' A
Gas Journal Spteol (November 26. 1990).
Exhibit 4-10
Capital Costs for Pipeline injection
Gathering Unas to Main .Commercial Pipeline
Basin
Central Appalachian
Northern Appalachian
Illinois
Warrior
Western
Sources used to develop rang
, DoBarsperMBe
Low
9650,000
$450,000
$200,000
$500,000
$650,000
Medium
9750,000
»550,OOO
$300,000
$600,000
$800,000
High
9850,000
•650,000
9400,000
9700,000
$950.000
«*: 11 ICF Resources 1990; 2) Warren ft True 'Pipeline Economies' Off 4
at 26. 1990).
enrichment of mine gas. Current estimates for these costs range from 91 .OO/mcf ta
$2.00/mcf for various enrichment approaches. Some new technologies ara under
development that could have tower costs of 90.50/mcf. but these have not been
demonstrated.
industrial Boilers. The cost of adding capacity for gas combustion at industrial facilities
will depend on the site and the retrofit requirements. Retrofits for full boiler conversion
(to 100 percent capacity with gas) can range from. 91,500/kJ to 93.000/kJ. with sizes
ranging from 40 kJ to 250 kj (Glickert. 1992). It would thus cost about 9200.000
to convert an average sized boiler rated at 120 kJ to gas. Additional costs would
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COAL MINING
17
include the gathering of the gas, any necessary compression and processing, and
transportation -from the point of compression to the boiler site.
Availability
All of the above technologies are-commercially available and are in use in various countries.
In countries where the equipment is not locally manufactured it may be possible to import
used equipment or modify existing equipment.
Applicability .
Enhanced gob well recovery, whan combined with suitable utilization options, is an
appropriate strategy for mines where more advanced techniques are not already in use or are
found to be impractical. In many cases, recovery and utilization techniques will build upon
existing practices.
Medium quality gas can be used in many countries for a wide range of utilization options.
Some countries, especially developed countries, may have gas Quality standards which
prohibit the distribution of a medium quality gas for residential fuel use and therefore reduce
the overall marketability of noh-oipeiine quality gas. in these countries, power generation or
on-srte industrial uses (e.g., coal-drying) may be the most feasible options. In countries with
fewer restrictions on medium quality gas use, the full range of options may be applicable.
Barriers . .
Barriers to the development of these recovery and use options will depend on the country and
the technology used, but frequently include: investment capital shortages, lack of resources,
difficulties in maintaining gas quality, and regulatory or institutional barriers- related to a
country's coat mining or energy sector. To address the technical difficulties, methane content
can be carefully monitored and methods to compensate for heat value variations can be
implemented. Overcoming regulatory, legal or institutional barriers may require changing
legislative or legal frameworks. To .he extent that particular policies'have reduced the
economic attractiveness of projects, moreover, it may be necessary to remove energy
subsidies, rationalize prices, and/or provide incentives to encourage methane utilization. ,
Benefits
fn addition to the reduction of methane emissions into the atmosphere, other benefits will be
.seen from the recovery and use of coaibed methane:
• Mine safety will be improved. Because methane drainage is improved with the
enhanced gob well recovery strategy, the methane concentration in the mine is
reduced, which* may result in fewer methane-related accidents at mines.
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18
COAL MINING
* Ventilation costs will decrease. One mining company in Alabama. U.S. has been able
to increase coal production while decreasing ventilation costs by using improved
methane recovery techniques/ This mine has estimated that capital expenditures of
$15 million would have been required for additional ventilation shafts arid fans
necessary to ventilate the same amount of methane which is now being recovered at
a profit (Dixon, 1989).
* A more efficient energy source will be used. Methane can be a more efficient fuel than
coal, particularly in residential cooking and heating end-uses. Many countries,
including China, use coal extensively for residential purposes (JP International. 1990).
Coal combustion cannot respond efficiently to low load operation, nor is it easy to start
and stop operation as the heating load swings, i.i comparison, gas can respond
instantaneously to heat demand and can be used for low load operation, thereby
providing a more efficient fuel, source.
• Less SO2, NOX, and paniculate emissions will be produced by the displacement of co. l
with gas. Natural gas combustion produces virtually no S02 emissions, no paniculate
emissions, and lower NOX emissions. A 10 percent increase in gas use in a retrofitted
coal-fired burner will result in a 10 percent decrease in SO2 and particulate emissions.
In many countries, expanded natural gas use is being aggressively pursued in response.
to serious local air pollution problems (Piicher et al., 1991; Bibter at at., 1992).
Enhanced Gob WeO Recovery and
Utilization
* up to 50% methane reduction
• improved mine safety
• improved mine productivity
• competitive with alternative gas
sources
• augments existing practices
• technology currently available
• clean energy source
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COALMINING ; 19
3 Pre-Mining Degasification
Pre-Mining Degasification \ss strategy that produces methane from targetetfcoal seams prior
to active mining. Unmmed coal of high rank, such as bituminous coal, may contain as much
as 10 to 20 cubic meters of methane per metric ton of coal (Kim, 1977). Additionally, larger
quantities of methane are stored in the surrounding rock strata. During mining operations, this
methane can also fiow into the mine workings where it may create a severe safety hazard.
Conventional methods for removing mine gas dilute the gas and vent it into the atmosphere.
Pre-mining degasification recovers this otherwise wasted resource before mining begins,
thereby increasing utilization options and Deducing the methane emissions associated with
future mining activities.
Recovery Technology Description .
•The two primary recovery technologies are in-mine.horizontal boreholes and vertical wells
drilled from the surface. Both techniques can be implemented anywhere fro.ii six months to
several years prior to the commencement of active mining operations, depending upon the
amount of degasification required and various geologic factors such as the methane content •
. and permeability (USEFA, 1990). Drilling horizontal boreholes is an in-mine technique; vertical
wells are drilled from the surface. Both techniques remove methane from areas of the coal
seam that are not yet exposed to ventilated mine workings, and as a result typically produce
higher quality gas than the "Enhanced Gob Well Recovery" approach. Furthermore, unlike gob
gas recovery, pre-mining degasification does not depend on active mining operation to
stimulate methane emissions. As a result, gas production can.be more reliable over longer
periods of time; '. ' .
Horizontal Boreholes: Horizontal boreholes have been used extensively for methane
drainage, especially in the United States and some European countries. These boreholes
are drilled into the unmined coat seam itself, in contrast to cross-measure boreholes which
are angled up into coal and rock strata at the boundary of the gob area (see "Enhanced
Gob Well Recovery"). The boreholes are typically a few hundred meters ion?. All
horizontal boreholes are drilled and produce methane prior to mining.
In general, horizontal boreholes are longer than cross-measure boreholes and therefore
Vequire more powerful drilling equipment. They can be drilled in two ways: 1) into the
longwall paoel^or 2) into mine development areas prior to the preparation of panels for
mining. In the.first case, horizontal boreholes are drilled across the width of a developed
longwall panel and typically produce gas for a period of several months until they are
mined through. These boreholes are generally a few meters shorter than the width of the
longwall panel. In the second case, much longer boreholes can be drilled into the coal
reserves from development headings and drain gas for several years in advance of mining.
As with cross-measure boreholes, horizontal boreholes are connected to an in-mine piping
system often operated under negative pressure to. remove the gas. However, the gas
quality is higher, typically over 95 percent methane. Production volumes vary with local
geology and borehole length, and have ranged from 700 co 5.000 m3/day (Trevits and
Finfinger. 1986; Baker et at.. 1986; Kline et at., 1987). Useful production lifetimes a'e
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20
reported to be from six months to several years. The production lifetime is limited by how
far in advance the mine is developed or the longwall panels are defined and laid out.
Horizontal boreholes are not as effective for degasification when coal seams are steeply
inclined or have very low permeability, as is the case in many of the world's coal
producing countries -such as Japan and China. In these countries, pro-mining
degasification is carried out using cross-measure boreholes drilled from a gallery under the
coal seam (Higuchi, personal communication). Boring stations are typically located every
50 to 100 m (160 to 330 ft) along the gallery, and a number of boreholes are drilled from
each station. Borehole spacing depends on coal and geologic characteristics, and they are
usually spaced 10 to 25 m (30 to 80 ft) apart.
Vertical Wells: begasification using vertical wells drilled from the surface is a- more
recently developed technology that has been commercially demonstrated in independent
gas production and coai mining operations. Vertical degasification wells are similar to
conventional oil and gas wells and are drilled into the coal seam several years in advance
of active mining. This technology is more advanced than the use of in-mine boreholes
because of the greater depth of drilling, the need to drill through rock rather than coal, and
the need to-stimulate the reservoir in order to produce gas.. Despite this, suitable
technologies have been developed and are widely available. The advantages of drilling
from the surface include avoiding working in the mine, and the ability to degasify the coai
seam many years prior to mining.
Because of the vertical orientation of the well, only a few maters of the coai seam will be
exposed (i.e., the height of the coal seam), in contrast to the hundreds of meters exposed
to an in-mine borehole. Depending on the permeability of the coal seam this may limit the
desorption rate of the methane into the well, thereby limiting overall recovery potential.
In order to overcome this, fractures can be induced in the seam by hydraulic fracturing (or
stimulation), a process in which a sand and water mixture is pumped under pressure imp
the wellbore. This fracturing process increases the permeability of the seam by creating
pathways through which the gas can flow.
Care must be exercised in the design and execution of hydraulic fracturing to ensure that
the future mineabiiity of the coai is not jeopardized: Many coal miners are concerned that
uncontrolled fracturing could weaken roof rocks and reduce mine safety whan the area is
mined through. Experirr.ants in U.S. mining regions have shown that hydraulic fractures
can be controlled arid should not adversely affect future mining (Deut. 1986). In fact,
several coal mines in the U.S. are using vertical degasification and hydraulic fracturing to
recover methanp.in advance of mining (Consolidation Coal Company, 1992; Oxy USA,
1932). When these technologies are used in other basins, however, care must be .taken
to protect the integrity of the coal. .
After fracturing, water must be removed from the coal formation hi order to produce gas.
Removing water (which is naturally occurring and also added during hydraulic stimulation)
decreases the hydrostatic pressure on the coai seams, thereby allowing gas to desorb from
the coal. Coalbed methane wells usually produce substantial quantities of water during
the first year of production, after which water production decreases and stabilizes over
a long period of time. Methane production peaks after the initial dewatering, and declines
slowly (10-20 percent/yr) over the lifetime of the well (USEPA, 1990). Recovered water
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COAL MINING
2!
must be disposed of by direct land application, discharge into streams or rivers, deep well
injection, or in evaporation pits.
The quality of produced water varies depending on geologic characteristics; in some cases
the water is potable, while in other cases it has high concentrations of dissolved salts and
other solids. The quantity and quality of the produced water, as well as applicable
regulations, will determine what disposal or treatment method is required. Where large
quantities of water, poor quality, or local regulations necessitate advanced treatment (such
as deep well injection of desalination) the disposal costs can be substantial.
Pre-mining degasification using vertical wells may be a very effective method of reducing
the methane content of coal seams and could consequently .reduce the emissions from
mining operations. Recovery rates of up to 70 percent over a 10 year period have been
documented using this technique (USEPA, 1990). Gas quality is high (over 90 percent
methane) because the methane is not diluted with ventilation air. Production rates depend
on reservoir and geological factors, the success of hydraulic stimulation, coal rank, and
well spacing. .
Where the techniques described above are already in place, it is often possible to increase
recovery efficiency througn improved drilling techniques, improved pumping and in-mine piping
systems, and the use of more advanced monitoring and control systems. These
improvements have been discussed above (sae "Enhanced Gob Well Recovery"}.
Utilization Technology Daacrforion
Pre-mining degasification typically yields high quality gas, with a heat value greater than 32
MJ/m3 (950 Btu/cf). The recovered gas can be used in any of the applications described
above for medium quality gas (in "Enhanced Gob Walt Recovery"), including electricity
generation, gas distribution systems, -and industrial heating. High quality gas will be a
preferred fuel because it does not cause some of the technical problems associated with
burning fuel with a lower heat value. In addition to the previously described uses, gas that
consistently contains 95 percent methane is "pipeline quality," and can-be sold in high quality
pipeline systems
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22
COAL MINING
The gas is compressed and propelled through the gathering lines to the pipeline. The
required compression is a function of the compressor's inlet pressure, outlet pressure, and
rated capacity. Pressures typically range from 200 to 800 psi (ICF Resources, 1990cK
Chemical Feedstock: Methane is a feedstock (i.e.. a raw material) in several important
chemical processes, such as the synthesis of ammonia, methanol, and acetic acid. In very
gassy areas, pre-mining degasification can recover the large quantities of consistently high
quality methane required to supply chemical plants. The smallest plants typically require
about 5 to 10 million standard cubic feet per day (280.000 cubic metersHXytei
Technologies, 1992), although smaller plants may be feasible. Alternatively, coalbed
methane from several mines could be collected at a central location in order to meet this
required volume.
Costs
Total project costs will include both the costs associated with methane recovery and the costs
associated with gas utilization. A range of costs associated the two pre-mining recovery
technologies — vertical wells and in-mine boreholes - are summarized below. Many of the
utilization costs have already been presented in the discussion of gob well costs, but those!
costs associated with unique utilization options, such as chemical"feedstock, are also'
presented in this section.
Recovery Costs: * The costs associated with recovering methane in advance of mining
using vertical wells and in-mine horizontal boreholes are summarized below. These costs
are based on U.S. experiences and technology and they are presented in U.S. dollars.
• Vertical Wells. The costs associated with recovering methane in advance of mining
using vertical wells are higher than for gob welts, because these wells require
additional completion and hydraulic stimulation and because it is necessary to dispose
of the produced water. As with vertical gob wells, the capital costs will vary between
and within basins depending on the depth of the wetta and site specific conditions,
which can influence the completion method used, the type of stimulation, the amount
of water produced, and the method of water disposal required.
Exhibit 4-11 summarizes the capital costs associated with .vertical well drilling.
completion and stimulation in the United States. The costs of surf ace-rights and site
development>re also included in these figures. The costs associated with coal basins
in the eastarrf United States tend to be lower as compared to western basins because1
the eastern basins are usually shallow.
The operating costs of vertical wells will depend on the number of wells in operation
and on annual gas and water production. .The per well recovery costs are associated
with the operation, maintenance and administration of the producing wells. They
should be quite similar to those for vertical gob wells and are assumed to remain fixed
over the lifetime of the well regardless of the amount of methane recovered. The
operating costs could range from $4,000 per well to $8.000 per weH, depending on
site specific conditions (ICF, 1992).
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COAL MINING
23
Exhibit 4-11
Capital Costs for Vertical Weils (per well costs}
Basin
Central Appalachian
Northern Appalachian
Illinois
Warrior
Western
Note: Capital costs for vemc.
preparation, drilling, completii
Sources used to develop rang
Recovery from Coat Seanjs (f
Resource and the Mechanism
Methane Technology 'Develop
Market Study of future Coa/0
Low
560,000
550,000
. $45,000
'$ 90,000
$320,000
Medium
$140,000
$125,000
$115,000
$190,000
$450,000
High
$225,000
$205,000
$'. 95,000
$290,000
$580,000
il wells include a« costs for surface drilling rights, site development and
ig and equipping the wells and hydraulic fracture treatment.
es: 1 ) US&A 1 990; 2) A Technical and economic Assessment of Methane
Tepared by ICF Resources. Inc. for USB»A, 1990}; 31 The Coaloed Methane ;
t of Gas Production (Gas Research Institute. 1989); 4) economics and
» Ventures (Ammonite Resources, 1991); SI Hunt and Steete Coaloed
mem in the Appalachian Basin (prepared for Gat Research institute, 1991 );
erf Methane Activity (Spears and Associates, 1,991). .
Vertical wells typically produce significant quantities of water during the first months
of operation, which must be disposed of in an environmentally safe manner. Water
disposal costs will vary for individual mines depending on geologic conditions and
applicable environmental regulations.
The capital costs for water disposal systems can range from $0.30/barrel of water to
$3.30/barrel of water. The low end of this range is associated with stream discharge
with little tr&ai/nent, a practice thai is sometimes practiced in the Warrior basin.
Medium costs of $0.90/barrel of water would be associated with stream discharge
with treatment, or land application with treatment, as is practiced in the Warrior basin.
The high end of this range is associated with the cost of disposal wells or evaporation
pits, which are often necessary, as is the case in the Western U.S.
The operating costs for water disposal can vary significantly depending on tii* disposal
method used. Gtr.erally, the stream or river discharge disposal method has the lowest
operating costs. Evaporation, pits, surface application, and stream or river discharge
with treatment, deep well injection and commercial off-site disposal have higher
operating costs. Operating costs for water disposal can range from $0.40/barrel of
water to $1.00/barrel.
The methane production costs (in $/mcf> will vary significantly depending upon
numerous site-specific factors, such as depth of drilling, completion and stimulation
methods used, water disposal requirements, and gas production. Low costs could bs
-------
MINING
in the range of $1.00/mcf, and high costs could reach S3.50/mcf or more.
production costs increase, project economics become less attractive.
As
• In-Mine Boreholes. Tha costs for in-mine horizontal boreholes have been estimated by
the U.S. Bureau of Mines and others (Baker, 1986; ICF Resources, 1990a). The total
system costs associated with several U.S. projects - including the boreholes.-methane
collection system, gas transmission system, and methane sensing system -are
reported to range from $25/foot of borehole to $35/foot of borehole. These costs
include both amortized investment and system operating costs. Capital and operating
costs for drilling alone are reported to range from $10 to $15 per foot of borehole.
The cost of in-mine piping systems may be about $5/foot of pipe.
The costs of in-mine systems will of course be highly site-specific. Conditions within
the mine will determine the number of boreholes drilled and their gas production rates.
Likely gas production costs could range from $1.007mcf to $4.00/mcf or higher.
Utilization Costs: The utilization costs for several options ~ including power generation
with turbines and 1C engines, pipeline distribution, and use in industrial boilers - were
summarized in the section on gob well recovery. One additional utilization option may be
attractive where high-quality methane is recovered: the use of methane aa a chemical-
feedstock. The costs for this option will include the costs associated with the process,.'
as weH as costs related to collecting and transmitting the methane to the point of use.
These costs will be highly variable depending upon the feedstock process selected and the
amount of gas to be processed.
Availability
All of the above technologies are commercially available, but may not be feasible in certain
regions for technical or economic reasons. In countries where the equipment is not locally
manufactured, it may be possible to impart used equipment or modify existing equipment.
Factors affecting applicability and barriers to implementation are discussed in the following
sections.
AooHcabtiftv
Prft-Mir.bg Degaaifieation is an appropriate strategy for very gassy mines where more
advanced technique* are already in use. or may be easily introduced. In many cases, recovery
and utiiization'techniques wilt build upon existing practices.
High quality gas. is a valuable energy source or raw material that can be used in many
countries. Developed countries, in particular, are likely to have pipeline infrastructures which
would allow the distribution of high quality gas for commercial sale and/or residential fuel use.
The price-for natural gas varies considerably from region to region, however, and can have
a large effect on the applicability of commercial sate as an option (including use as a chemical
feedstock). Using high quality gas as a chemical feedstock would be attractive for gassy
mines in countries with substantial domestic petrochemical markets (e.g.. China and India are
both increasing their domestic demand for ammonium fertilizers).
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COAL MINING
25
Barriers
Barriers to the development of these recovery and use options will depend on'the country and
the technology used. Frequently encountered barriers include investment capital shortages,
lack of local resources, lack of technical experience, low gas prices, and legal or regulatory
constraints. Some of the barriers .can be overcome through technology demonstration,
training, and technical assistance in regulatory development. In other cases, it may be
necessary to restructure energy sectors, rationalize energy prices, and provide assistance in
the development of viable gas markets. Additionally, because the use of recovered methane
as a feedstock requires transport to the point of sale, feasible proximity to commercial users
must be considered.
Benefits
In addition to reducing methane emissions into the atmosphere, pre-mining degasification will
result in several other benefits:
• Mine safety wilt be improved. Because methane drainage is greatly improved through
pre-mining degasification. the methane concentration in the mine is reduced, which
may result in fewer methane-related accidents.
• Ventilation costs will decrease. One mining company in Alabama, U.S. has been able
to increase coal production while decreasing ventilation costs by using improved
methane recovery techniques. This mine has estimated that capital expenditures of
$15 million would have been required for additional ventilation shafts and fans
necessary to ventilate the same amount of methane which is now being recovered at
a profit (Dixon, 1989). *
, • A more efficient energy source wilt be used. Methane can be a more efficient fuel than
coal, particularly in residential cooking and heating end-uses. Many countries.
including China, usa coal extensively for residential purposes UP international, 1990).
Coal combustion cannot respond efficiently to low load operation, nor is it easy to start
and stop operation as the heating load swings, in comparison, gas can respond
instantaneously to hear demand and can be used for low load operation, thereby
providing a more efficient fuel source.
• Less SO2, NOX, and p-rticuiate emissions will be produced by the displacement of coal
with gas. Natural gas combustion produces virtually no SO2 emissions, no paniculate
emissions, and lower NO, emissions. A 10 percent increase in gas use in a retrofitted
coal-fired burner will result in a 10 percent decrease in S02and paniculate emissions.
In many countries, expanded natural gas use is being aggressively pursued in response
to serious local air pollution problems (Pitcher et ai.. 1991; Bibier et al.. 1992).
-------
26
COAL
Pre-Mining Degasification
* up to 70% methane reduction
• high quality gas
• long production lifetime
• improved mine safety
• improved mine productivity (up to
25% at gassy mines)
• competitive with other gas sources.
• technology currently available
• clean energy source
4 Ventilation Air Utilization
Ventilation air utilization presents an opportunity to use the considerable volume of mine gas
that is currently vented into the atmosphere in low concentrations from ail underground
mines. Developing usas for ventilation air can significantly reduce methane emissions to the
atmosphere from coal mining.
The release of methane into the mine workings presents a safety-hazard for all deep coal
mines, because methane is explosive at concentrations of 5 percent to 15 percent in air.
Most countries have regulations which require that methane concentrations be kept below 1
percent. The most common method of achieving this safety level is to dilute the methane
through the ventilation of the mine with large fans. Although additional techniques can be
used, ventilation is a necessity in all underground mines. As a result, large quantities of air
are removed which contain methane at an average concentration of about 0.5 percent
methane. At gassy U.S. mines, between 5 and 23 ~ns of air may be ventilated per ton of
coal mined (Skow et al,, 1980). Total methane emissions in ventilation air range from 0.5 to
15.0 million cubic feet a day of methane for gassy U.S. mines (Trevrts et al., 1991). Recent
estimates for the U.S. indicate that the venting of mine gas accounts for 50 to 75 percent of
ail methane releases from coat mining, and 75 percent of emissions from underground mines
(USEPA, 1993a>. -
' ' "' >
Although, the methane in ventilation air is dilute, its energy value may still be profitably
recovered. Efforts to reduce methane emissions from this source must focus on developing
uses for air that contains low concentrations of methane. The utilization techniques described
here involve using ventilation air as a supplemental or secondary fuel for the generation of
electricity in steam boilers and gas turbines. Depending on its concentration and the generator
technology, ventilation air could supply between 7 percent and 15 percent of a generator's
energy (or higher if methane concentrations are in excess of 0.5 percent), thereby reducing
primary fuel requirements and contributing to the electricity need of the mining' operation
{ESA. 1991).
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27
Recovery Technology Descriptions .
Recovery of the methane is not a.factor in this strategy- As noted above..ventilation of thc
mine wili occur as a matter of course in any underground mine, and utilizing the ventilation
air should have no negative economic or practical effect on mining operations. Since this
utilization option has not yet been demonstrated, however, it is important to design the
system in a manner that does not jeopardize the ability of the mine to dilute and remove the
methane from the mine workings. In addition, this option must be implemented in a manner
consistent with mine safety regulations. , < ; .
Utilization Technology Description
The utilization option discussed.in this section involves substituting tow concentrations of
methane in air for combustion air in coal-fired boilers or gas turbines, in either case the basic
concept is the same: generators obtain energy by burning a fuel/air mixture, with the fuel
being coal or gas. Because ventilation air from coal mines contains meth :ne, it has a heat
energy value which could reduce the amount of fuel required to create an explosive fuel/air
mix of combustion in a boiler or turbine.
For both coal-fired boilers and gas turbines, -the ventilation air must be ducted from the
ventilation shaft to the generating facility. Preliminary technical analyses indicate that the air
supply system can be readily constructed from galvanized steel ducts, typically 7 to 12 feet
(2 to 4 m) in diameter (ESA. 1991K Fans and motors will likely be necessary if the supply
distance is over 1000 feet (300 m). The energy needs of the fan motors must be balanced
against the energy value of the mine gas - at some point, depending on duct length, capacity,
and pressure, more energy will be required to transport the gas to the generating facility than
can be recovered during combustion. It appears that this distance is on the order of 3 miles
(5km). .
i
Coal-fired Boilers: * Coal-fired boilers burn pulverized coal mixed with large amounts of
combustion air to produce steam, which in turn is used to generate electricity. Typically,
13 pounds of air are needed for every pound of coat that is burned (i.e., a 13:1 mass
ratio). This translates to approximately 14O standard cubic feet (4^m3) of combustion air
per hour, for each kilowatt (SCFH/kW) of generating capacity, but the ratio will vary with
coal type, boiler efficiency, and the amount of exces&air used in combustion (ESA, 1991).
Preliminary technical feasibility studies indicate that ventilation air can be transported
through the air ducts of most types of boilers without compromising safety or otherwise
affecting standard operation. The methane should therefore be easily introduced into the
boiler, where it will bum and produce, heat. 140 standard cubic feet of ventilation air .(i.e.,
the approximate amount needed to produce 1 kWh of electricity), containing 0.5 percent
methane, has a heat value of 700 Btu (74O kJ). Ventilation air containing O.5 percent
methane could provide 7 percent of the boiler's energy (ESA, 1991). Replacing the
primary fuel, coal, with methane could also improve boiler economics through reduced fuel
purchasing, handling, and preparation costs, less furnace slagging and ash production, and
' tower emissions of particulates, sulfur dioxide and nitrogen oxides.*
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23
Gas Turbines: A gas turbine uses heat obtained from the combustiorT of a fuel/air mixture
to raise the temperature of compressed air. The hot compressed gas powers a turbine
which generates electricity. Gas turbines use large quantities of combustion air in the
fuel/air mixture, typically 350 SCFH per kW of generating capacity for turbines with
capacities between 1 and 100 MW. Based on ventilation air containing 0.5. percent
methane. 350 SCFH would provide 1750 Btu/kWh, or about 15 percent of a typical
turbine's energy requirements (ESA, 1991}.
Secause turbines use larger quantities of combustion air than coat-fired boilers, and thus
gain a higher energy contribution from ventilation air they are an attractive option for
ventilation air use. Additionally, the simpler technology, lower capital and maintenance
costs, shorter construction lead times, and the large range in available generating
capacities make turbines extremely suitable for use at coal mines.
The applicability of these techniques must be determined by an analysis of many site-specific
factors, including the compatibility of the volume of ventilation air with combustion air
requirements, the mine operation power requirements and/or local energy markets, and the
proximity and design of the generating plant. A discussion of relative energy costs is
presented in the following section. <
Costs ' . .
The underlying factor in choosing to use ventilation air as combustion air is the relative energy
cost of supplying ventilation air. If low concentration methane is to replace some percentage
of the primary fuel requirements for electricity generation, the ventilation air must be supplied
at a lower cost per unit of energy than the primary fuel.
In terms of fuel costs, supplying low quality methane is attractive if the combustion devices
are located in close proximity to the mine, in this situation, the capital costs of the ducting
should be low and the operating costs associated with running fan motors minimized. For a
.range of air flows from 2 MMSCFH to 80 MMSCFH (compatible with turbine sizes of 5 MW
to 230 MW respective'y), costs are estimated to be $0.08 to over 91.60 per MMBtu,
depending on the distance and methane concentration (ESA. 1991). To tine extent that new
ventilation shafts are opened as mining proceeds, it may be necessary to move the fens and
ducting every few years, which could increase costs. In comparison to current U.S. costs of
$1.50 to $4.00/MMBtu for conventional turbine fuels (e.g.. natural gas and *2 fuel oil) the
economics of supplying ventilation air to mine-site gas turbines appear attractive in many
cases i=3A, 1991). ~
Energy costs rise when the ventilation air is transported some distance, from the mine site.
in this situation, higher methane concentrations and flow rates will increase the overall
attractiveness of the project. For example, supplying air containing 0.5 percent methane at
a flow rate of 40 MMSCFH (compatible with, a 285 MW coal-fired boiler) would cost
approximately $1.25 MMBtu at a distance of 3 miles (ESA, 1991). In comparison, delivered
coal costs are approximately * 1.50/MM8tu in the U.S.. rising to $ 1.75- S 2.00/MMBtu if costs
for preparation, pollution control and ash disposal are included.* Exhibit 4-12 shows estimated
break-even energy costs for ventilation air use based on duct length, methane content, and
air flow.
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COAL. MINING
29
Exhibit 4-T2 J
Break-Even Energy Costs for Mine Ventilation Air
Distance
(miles)
< 0.5
1.0
• 3.0
< 0.5
1-0
< 0.5
1.0
3.0
Concentration
(%CH4)
' 0.5
0.5
O.S
0.25
. - • 0.25
1-0
1.0
1.0.
Gas Flow (mmscfhj
Turbine-Capacity (MW1
Boiler Capacity
,•
" .
2
6
14
20
57
143
40
114
286
80
229
572
Break-Even Energy Cost (S/mmbtu)
0.8
> 1.6
>. 1.8
n/a
n/a
n/a
n/a
n/a
0.2S
0.55
> 1.6
n/a
n/a
n/a
a/a
n/a
0.18
0.3S
1.25
0.5
0.8
0.08
0.18
0.5
0.13
0.28
1.25
n/a
n/a
0.08 .
O.I 3
0.42
Source: ESA. 1991.
Availability , .
The recovery, transportation, and combustion of ventilation air uses equipment and
technology that is commercially available and accessible. However, this concept has not yet
been demonstrated and pilot projects should be undertaken to determine.if this strategy is
feasible.
AooBeabHitv
Large quantities of ventilation air are vented by every operating underground mine. .These
emissions constitute an untapped energy resource that can potentially be utilized, if a
technical demonstration is successful, the utilization of ventilation air should be considered
for every mine. However, there are economic and practical requirements that will limit the
number of feasible project locations. The crucial factors are whether the methane in the
ventilation air can be reliably supplied to the combustion device in sufficient quantity at an
energy cost lower than the primary fuel, and whether the project can be implemented in a
technically feasible manner that does not adversely affect mine safety or the safety of
-powerplant operation. .
Ventilation air use may be economically attractive in certain locations if it is proven technically
feasible. Additionally, where primary fuel is available and electricity demand is expected to
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30
COAL MINING
grow, meeting this demand by installing gas turbines in the vicinity of underground coal mines
may be a feasible strategy that more efficiently utilizes local resources.
Despite the potential for utilizing this resource, there are several barriers to implementation.
Most importantly, the technical viability of this utilization option has yet to be demonstrated.
institutional interest and awareness of the potential is often lacking, as are incentives to
consider ventilation air as an energy source. In addition, the massive volume of iow quality
gas that is produced is itself a barrier. Generally, utilizing all the ventilation air produced by
a mine would necessitate a larger generator than is required for mine operations alone. As
a result, full utilization of mine ventilation air requires external electricity markets and a
transmission infrastructure; this reliance on specific conditions in other sectors of the local
energy market may present a barrier to project implementation.
Benefits
In addition to the reduction of methane emissions into the atmosphere, other benefits will be
seen from the utilization of ventilation air:
• Reduced use of primary energy sources and/or increased generating capacity. The use
of ventilation air in electricity generation can reduce primary energy source use by up
to 30 percent. This is a more efficient use of energy resources, and can reduce
reliance on foreign energy sources.
• Less SO2, NOX, and paniculate emissions will be produced by the displacement of coal
with gas. Natural gas combustion produces virtually no SO2 emissions, no paniculate
emissions, and lower NOX emissions. A 10 percent increase in gas use in a retrofitted
coal-fired burner will result in a 10 percent decrease in SQ2 and particulate emissions.
In many countries, expanded natural gas use is being aggressively pursued in response
to serious local air pollution problems (Pilcher et at.. 1991; Bibler at el., 1992).
Ventilation Air Utilization
10-90% methane reductions
efficient use of energy resources
competitive energy costs
augments existing practices
technology currently available
demonstration projects necessary
clean energy source
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COAL MINING
"
31
Integrated Recovery
An integrated system of methane recovery and utilization can take full advantage of ail the
available strategies for reducing methane emissions from coal mining. In many mines, using
two or more methane recovery approaches (e.g.. pre-mining degasification with horizontal
boreholes and vertical gob wells) can: 1) optimize mine degasification, achieving the
maximum improvements in mine safety and productivity; and 2) realize economies of scale
as fixed costs are shared (Exhibit 4-13).
Recovery Technology Description
Developing the capability to implement a variety of methane recovery techniques enables an
optimal response to site-specific field conditions. The available methane recovery
technologies have each been described in the technical assessments above. Each technology
can effectively reduce methane concentrations in mines. Nevertheless due to certain
geological or technological factors it may be desirable to implement a combination of
strategies. For example, if methane reductions of 50 percent are required to maintain coal
production most economically while ensuring mine safety, an optimal strategy may be to
combine gob welt recovery with pre-mining drainage. This has been the experience of at least
one mrnrnq operation in the United States (Dixon, 1987), and many mines in the U.S. and
throughot >t the world use a variety-of degasification techniques to optimize methane recovery.
in addition to technical advantages, economies of scale may be realized in integrated projects.
Utilization Technology Description
As with recovery technologies, the utilization technologies that have been previously
described may be combined to optimize gas use. The compatible combination of end uses can
improve technical and economic feasibility. -
Costs
integrated recovery projects will typically be larger than projects employing single strategies:
capital costs, are expected to be correspondingly larger. However, unit costs may fa* lower
due to economies arising from the implementation of mutually beneficial technologies..
Economies of Scale: Several of the techniques use similar technology, equipment, or
drilling practices, and require similar technical capabilities. Irirmine piping and surface
gathering and processing equipment are often compatible .with different projects.'
Therefore, certain fixed costs associated with capital expenditures, support facilities.
training,- and maintenance may be spread over several types of methane recovery. Even
where this is not the case, common costs of project planning and overhead can be shared
for integrated strategies. ,
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32
COAL MINING
Economies of Scope: The most promising potential for integrated systems lies in the
mutual benefits of coordinating utilization strategies. For example, one of the significant
barriers to utilizing ventilation air as a supplementary combustion fuel is the supply of
competitively priced primary fuel for gas turbines {see "Ventilation Air Utilization").
Conventional supplies of gas turbine fuel, natural gas or #2 fuel oil, can cost between
$1.50 and $4.00 per MMBtu, which is often enough to make the installation of a turbine
uneconomical. However, coordination of a degasification or gob well recovery project
with the combustion of ventilation air can provide a significantly less costly supply of
primary fuel; medium quality gas (as low as 30 percent methane) is sufficient to power
a gas turbine. The integrated recovery and use of both low and medium/high quality gas
provides a direct demand for the medium quality gas, and removes a barrier to utilizing
ventilation air; independent of one another, these projects may not be feasible.
Exhibit 4-13
Integrated Recovery
Gas use
Note: not drawn to scale
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Coat MINING
33
Mutual advantages may also exist for issues of technical feasibility. Active gob gas recovery
will reduce the volume of ventilatron air necessary to maintain mine safety. As a result, a
smaller and less costly turbine can be used, or a more significant proportion'of the ventilation
air can be consumed. Coordinating the production from both projects can optimize total
project economics and feasibility.
Availability "
Technologies for reducing methane emissions are available. However, certain countries may
need technical assistance in assessing the trade-offs between approaches fo developing
optimal integrated systems.
Applicability
There are significant benefits, associated with developing integrated methane recovery and
utilization projects. However, it is important to realize that these benefits are attained through
the implementation of larger and more technically advanced projects. This fact has a direct
impact on the suitability of integrated recovery projects. It is likely that integrated projects
will only be suitable for large mining operations working in relatively gassy coal seams. The
current trend in coal mining is towards deeper, and thus gassier mines, making the
implementation of integrated projects increasingly likely.
The barriers for integrated recovery will be similar to those facing any methane recovery
project, though larger because of the additional scope, cost, and complexity. As a direct
result of the size and technical sophistication of these larger projects, capital expenditures and
operating costs will be correspondingly higher even though the long-term economics may be
more favorable. Similarly, equipment and training needs will .be more advanced,, as will
technical and planning expertise. Integrated projects will likely only be implemented by mining
operations that have significant previous experience, or with technology transfer assistance.
Benefits .
In addition to the reduction of methane emissions into the atmosphere, other benefits will be
seen from the integrated recovery and use of coalbed methane:
• Mine safety will be improved. Because methane drainage is improved with the
enhanced gob well recovery strategy, the methane concentration in the mine is
reduced, which may result in fewer methane-related accidents at mines. .
• Ventilation costs will decrease. One mining company in Alabama, U.S. has been able
to increase coal production while decreasing ventilation costs by using improved
methane recovery techniques. This mina has estimated that capital expenditures of
$15 million would have been required for additional ventilation shafts and fans
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necessary to ventilate the same amount of methane which is now being recovered at
a profif-(Dixon. 19S9). I
A more efficient energy source 'will be used. Methane can be a more efficient fuel than
coal, particularly in residential cooking and heating end-uses. Many countries,
including China, use coal extensively for residential purposes UP International. 1990).
Coal combustion cannot respond efficiently to low load operation, nor is iteasy'to start
and stop operation as the heating load swings. In comparison, gas can respond
instantaneously to heat demand and can be used for low load operation, thereby
providing a more efficient fuel source.
Less S02, NOX, and particulate emissions will be produced by the displacement of coal
with gas. Natural gas combustion produces virtually no S02 emissions, no paniculate
emissions, and lower NOK emissions. A 10 percent increase in gas use in a retrofitted
coal-fired burner will result in a 10 percent decrease in SO2 and particulate emissions.
in many countries, expanded natural gas use is being aggressively pursued in response
to serious local air pollution problems (Pitcher et al., 1991; Bibler et al.. 1992).
Oegasification will be optimized. The integrated use of suitable recovery technologies
can result in up to 90 percent methane reduction. Greater reductions can be achieved
while improving project economics.
I ntegrated Systems
up to 90% methane reduction
optimization of degasification
economies of scale
economies of scope
augments existing practices
technology currently available
dean energy source
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COALMINING
35
'' 6 References
Contributions were made by.
E. Dowdeswell, Environment Canada, Canada
Roger Glickert, Senior Engineer. Energy Systems Associates, USA "
Kiyosht Higuchi, Hokkaido University. Japan
Robert Kane, Global Climate Program Manager, U.S. Department of Energy, USA
Oina Kruger, Project Manager for Coalbed Methane, USEPA, USA
Carl Sturgill, independent Consultant. USA
Additional information may be found in the following:
Ammonite Resources (1990), "Economics and Financing of Coalbed Methane Ventures,"
presented by G.W. Hobbs and R.O Winkler, at The Eastern Coalbed Methane Forum.
Tuscaloosa, AL. January 16, 1990.
Anderson. C. (1991), Waste Management of North America, personal communication.
Octobers, 1991. -
Baker, E.C.. R.H. Grau til, G.L. Ftnfinger (1986). Economic Evaluation of Horizontal Borehole
Drilling for Methane Drainage from Coalbeds. 1986,1C 9080.
Baker. E.G., F. Garcia, J. Cervik (1988). Cost Comparison of Gob Hole and Cross-Measure
Borehole Systems to Control Methane in Gobs. U.S. Bureau of Mines, 1988, RI.9151-
Bibler, C.J.. J.S. Marshall, and R.C. Pilchard 992). Assessment of the Potential for Economic
Development and Utilization of Coalbed Methane in Czechoslovakia, prepared by Raven Ridge
Resources. Inc.. Grand Junction, CO. for USEPA. in press. -
Consolidation Coal Company (1992), update on Consol/Conoco project in Buchanon County,
VA. deiivered at the Fall 1992 Pittsburgh Coafbed Methane Forum Meeting. October 14,
1992. Morsantown, WV. ' .
Deul. M.. A.G. Kim (1986), Methane Control Research: Summary of Results. 1964-80. U.S.
.Bureau of Mines, 1986, B-687. --• ...
Diamond. W.Pi. J.C. Lascola. and D.M. Hyman (1986). Results of the -Direct Method
Determination of the Gas Content of U.S. Coalbeds. U.S. Bureau of Mines. 1C 8515. 36 pp.
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36
CCAL MINING
Oixon, C.A. ff987), "CoaJbed Methana ~.;A Miner's Viewpoint," in Proceedings of the 1987
Coalbed Methane Symposium. Tuscaloosa, Alabama.
Oixon, C.A. (1989). Maintaining Pipeline Quality Methane from Gob Walls. Pittsburgh Cbalbed
Methane Forum. April 4, 1989. 7 pp.
ESA (Energy Systems Associates)! 1991), 'Opportunities for the Utilization of Mine Ventilation
Air." prepared for Global Change Division. USEPA, Washington. D.C. January. 1991.
Garcia, F,, and J. CerviK (1988), Review of Membrane Technology for Methane Recovery from
Mining Operations. U.S. Bureau of Mines Information Circular/1988,1C 9174, 6 pp.
Glickert. R. (1991). Energy Systems Associates, personal communication, August. 1991.
GRI (Gas Research Institute) (1989). "The Coalbed Methane Resource and the Mechanisms
of Gas Production* Topical Report prepared by iCF Resources, Inc. for Gas Research institute.
Contract Number 5984-214-1066. November, 1989. •
Granatstein, D.L.. A.L. Crandlemire. J.C. Campbell, P.P. Preto. B.G. King (1991). "Utilization.
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Technologies Meeting, Battalia Laboratories, Columbus, Ohio, September. 1991.
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Appalachian Basin. Topical Report prepared by Oames and Moore for Gas Research Institute.
Contract Number 5089-214-1783, January, 1991.
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Coal Mining. Revised Draft Report, prepared for USEPA by ICF Resources, Inc. with
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ICF Resources (1990b), A Technical and Economic Assessment of Methana Recovery from
Coal S»ams. prepared for USEPA/OAR,(Offica of Air and Radiation).
^_ "
ICF Resources (1990C). The Potential Recovery of Methane from Coal Mining for Use in the
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Intergovernmental Panel on Climate Chance. U.S. Environmental Protection Agency.
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COAL MINING
37
Kim, A.G. (1977), Estimating Methane Content of Bituminous Coaling from Adsorption Data
U.S. Bureau of Mines, Ri 8245, 22 pp.
Kline, R J.. L.P. Mokwa, and P.W. Blankenship (1987), "Island Creek Corporation's Experience
with Methane Oegasification," in Procaedinos of the 1987 Coalh»d. Methane Symposium
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Moerman, A. O982J, "Internal Report on Gas Storage in Peronnes-lez-Binche, Belgium, S.A.
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Oxy USA (1992), Update on Oxy USA project in Buchanon County, VA, delivered at the Fail
1992 Pittsburgh Coalbed Methane Forum Meeting, October 14, 1992, Morgantown, WV.
Pilcher, R.C., CJ. Bibier. R. Gtickert, L. Machesky, J.M. Williams (1991). Assessment of thg
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Spears & Associates, Inc. (1991), Market Study of Future Coalbed Methane Activity.
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3Ai. MiMNC
. DC P*p«d by .CF R,s=u,=B, inc.. SwniAr19«0.«P««00»
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visit to Moscow, Russia. •.
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