United States
Environmental Protection
Agency
National Risk Management
Research Laboratory
Cincinnati, OH 45268
Research and Development
EPA/600/SR-97/152 January 1998
-------
able, and many of these techniques are
capable of reducing methane emissions
while simultaneously creating new sources
of revenue and energy for a mine. The
U.S. Bureau of Mines has conducted nu-
merous feasibility studies which provide
guidelines on successfully implementing
degas technologies. However, many mines
still do not use these systems, and those
that do, do not utilize the recovered gas
— they simply vent it to the atmosphere.
Causes of the lack of utilization include:
costly investments required for equipment
and personnel, poor understanding of costs
and revenue potential, conflicts in gas own-
ership rights (especially in the Northern
Appalachian Basin), and a higher priority
for coal mining rather than utilizing coal
mine gas.
The report gives results of a national
engineering and economic assessment of
coal mine degas and gas utilization sys-
tems. The evaluation was conducted by
examining the application of degas/utiliza-
tion systems applied to a group of repre-
sentative mines operating in all major U.S.
coal basins. The emissions and economic
performances of various technologies were
developed using site-specific mine design
and geological parameters, and cost analy-
ses models developed and quality assured
with the assistance of mine operators, min-
ing consultants, degas system consultants,
degas system research organizations, and
the U.S. Bureau of Mines.
Study Overview
Prior to executing the analysis, a sub-
stantial effort was launched to gather and
analyze the engineering, economic, and
geological data needed to define key study
parameters. Using the data collected,
groups of parameters were defined in-
cluding: (1) the population of mines in
each major basin, (2) the design and cost
of coal mining in each basin, (3) the level
of methane control and utilization mines
currently employ, (4) the performance and
availability of established and developmen-
tal methane control and utilization strate-
gies, and (5) the design and cost param-
eters for these methane control and utili-
zation strategies. The engineering and cost
data collected were used to develop a
detailed engineering and economic analy-
sis model. This model automated the la-
borious tasks of calculating underground
mine design parameters and costs for dif-
ferent mining regions, determining degas/
utilization system design factors and costs,
and integrating the feedback effects which
degas systems have on normal mine op-
erations.
Nine underground mines, referred to as
"standard mines," were defined to repre-
sent the population of underground mines
operating in the five major coal producing
regions of the U.S. The regions examined
were the Black Warrior Basin (Standard
Mines 1 and 2), the Central Appalachian
Basin (Mines 3 and 4), the Northern Ap-
palachian Basin (Mines 5, 6, and 7), the
Illinois Basin (Mine 8), and the Western
region (Mine 9). These standard mines
are similar to actual mines: (1)they share
the same coal production rates, methane
emission levels, and degas systems, (2)
they are located in the same geographic
region, and (3) they are identified with the
same coal seam stratigraphy. Table 1 sum-
marizes key parameters used to define
these nine mines.
The suite of mines examined were struc-
tured to exclude very small and low meth-
Table 1. Description of Standard Mines
Standard Mine No. 1
Region
Warrior
Warrior
Central
Appal.
Central
Appal.
North.
Appal.
North.
Appal.
North.
Appal.
Illinois
Western
State
County
Seam Mined
Mining Method
Coal Production (MMtpy)
CH4 Emissions (MMcfy)
From Vent. Systems
From Degas Systems
Total
Base Case System
Degasification
Utilization
Power Req. (MMkW-hr/yr)
Continuous Demand
Operating Demand
Electricity Purchase Price
($/kW-hr)
Excess Power Buy-Back
Rate ($/kW-hr)
Pipeline Distance (miles)
Wellhead Gas Sales Price
($/1000 ft3)
AL AL WV
Jefferson Tuscaloosa Raleigh
Mary Lee Mary Lee Beckley
LW
1.2
548
0
548
None
None
22.53
31.62
0.040
0.020
3
2.90
LW
2.4
6,351
2,446
8,797
GW&HB
None
63.39
51.90
0.040
0.020
10
2.90
R&P
1.0
694
0
694
None
None
32.51
18.55
0.045
0.023
3
2.00
VA
Buchanan
Pocahontas
No 3
LW
1.8
2,628
2,555
5,183
GW&HB
None
38.67
35.30
0.045
0.023
5
1.82
PA
Indiana
Freeport
R&P
1.0
402
0
402
None
None
30.52
18.55
0.063
0.032
1
1.91
PA WV IL CO
Greene Monongalia Franklin LasAnimas
Pittsburgh Pittsburgh Herrin No 6 Maxwell
LW
3.0
2,117
803
2,920
GW
None
44.78
27.27
0.063
0.032
1
1.91
LW
3.0
1,351
811
2,162
GW&HB
None
45.23
28.61
0.045
0.023
1
2.00
LW
3.0
767
365
1,132
GW
None
42.12
28.61
0.044
0.022
3.3
2.11
LW
1.5
1,862
913
2,775
GW&HB
None
36.18
26.12
0.035
0.017
23
147
MMtpy = million tons of coal produced per year
MMcfy = million cubic feet methane emitted per year
MMkW-hr/yr = million kilowatt hour per year
GW = gob wells
HB = horizontal boreholes
LW = longwall
R&P = room and pillar
-------
ane emitting mines because they neither
contribute significantly to national emis-
sions, nor are they good candidates for
the cost effective installation of degas sys-
tems. For each of the nine standard mines
examined, mine design and local stratig-
raphy were defined based on data com-
piled for actual sites operating in each
region. While several standard mines were
defined to currently use mine ventilation
as a primary source of methane control,
others were defined to use some form of
advanced methane control and utilization.
This is referred to as the base case meth-
ane control level, and is important here
because the base case technology forms
the benchmark against which the perfor-
mance and cost of more advanced tech-
nologies are measured.
A suite of available and developmental
degas technologies are examined here.
These technologies include: gob wells,
cross-measure boreholes, horizontal bore-
holes, conventional vertical wells, and ni-
trogen gas injection wells (developmen-
tal). Gob wells are drilled from the surface
to drain methane from portions of overly-
ing strata allowed to collapse after the
coal is removed. Cross-measure boreholes
also degas these areas but are drilled
from inside the mine. Horizontal boreholes,
conventional vertical wells, and gas injec-
tion wells are often referred to as "ad-
vance of mining" degas systems. These
systems recover gas from coal which is
slated for mining months or years in fu-
ture. Horizontal boreholes are drilled from
inside the mine, while conventional verti-
cal wells and gas injection wells are drilled
from the surface. Surface drilled wells re-
move gas from the primary mined seam,
but can also be installed to remove meth-
ane from gas bearing strata above and
below the primary seam. These, referred
to as multi-zone wells, provide the addi-
tional mining benefit of removing the some-
times substantial quantities of gas that
can enter mine workings from strata above
and below the mined seam. The gas in-
jection process is a relatively new tech-
nology which has never been demon-
strated at an actual mine site. It is in-
cluded here because several pilot tests in
the western U.S. show that it has the
capability to remove a large volume of
gas at a much faster rate than the con-
ventional wells described above.
Once gas is recovered from the coal
and brought to the surface, it can be uti-
lized in a number of ways. Two methane
utilization strategies are examined here:
on-site power generation with gas turbines,
and sales to a national transmission pipe-
line. These end-use technologies are se-
lected primarily because they have been
successfully used at coal mines, and show
the greatest promise of being used at
other sites. With the pipeline option, gas
purification systems are sometimes needed
to purify low to medium Btu gas to pipe-
line quality. The cost of the purification
systems is included with other equipment
and operating costs needed to execute
the pipeline option.
The engineering and economic data
used here were developed using industry
standard practices. The development of
mine design, degas design and perfor-
mance, and economic analysis procedures
were developed by Southern Research
with the direct assistance of coal mining
and degas system experts including the
John T. Boyd Company, the AMOCO Pro-
duction Company, Resource Enterprise
Incorporated (REI), the Bureau of Mines,
and Energy Ingenuity Company. Using
data and guidance from these and other
groups, a discounted cash flow analysis
was executed to determine the annual
profit, net present value, and internal rate
of return (IRR) for each standard mine
and base case control strategy. This analy-
sis was then repeated for the standard
mines, but with the addition of the suite of
different methane control and utilization
technologies described above. The eco-
nomic and emission reduction performance
of each degas technology is judged based
on its performance relative to the base
case technology. The results of these com-
parisons are summarized below.
Summary of Findings
Table 2 lists the most economically
promising degas and utilization technol-
ogy options identified for the nine stan-
dard mines examined. The table identifies
the mining region, the mine size, the base
case methane control used, the estimated
reduction in methane emissions, and the
most promising alternative degas technolo-
gies. Three economic parameters are pre-
sented: incremental net present value
(NPV), incremental annual profit, and in-
cremental internal rate of return (IRR).
The use of incremental values simplifies
the direct comparison of the base case
and the alternative degas technologies,
and are calculated by subtracting the NPV,
annual profit, or IRR of the base case
technology, from the values associated
with the alternative degas technology.
The summary below identifies a degas
technology as providing better economic
performance when: (1) NPV and annual
profit for the advanced degas technology
option exceed the values occurring with
the base case methane control technol-
ogy, and (2) the IRR is higher than 10%,
the discount rate of return. In many cases,
several degas options appear to provide
better economic performance. The follow-
ing summary of the trends observed and
findings reached is based on the data in
Table 2.
Mine-Specific Trends and
Findings
• Using one of the technologies exam-
ined in the study, all longwall mines
could potentially change their current
methane control practices to increase
profits and decrease emissions. In
general, one or more "win-win" meth-
ane control options were identified.
The room and pillar mines perform
poorly, primarily due to the low vol-
ume of gas encountered.
• Mines 2, 4, 6, 7, and 9 represent the
highest emitting U.S. operations. Each
mine currently uses gob wells or gob
wells with horizontal boreholes to re-
duce in-mine methane emissions, and
each has several available options
which provide better economic per-
formance to this technology. Utilizing
gas from already existing degas sys-
tems reduces methane emissions.
Additional emissions reductions can
also occur in these areas if multi-
zone conventional vertical wells are
utilized. However, these systems re-
quire large capital outlay.
• The most profitable option for the
mines identified with methane control
technology already in place (except
for Mine 8 in the Illinois Basin) is
utilization of the gas recovered from
the base case systems. The existing
degas system combined with gas tur-
bine or pipeline sales offer high IRRs
and annual profit ranging between $1
million and $6 million.
• The more gassy mines, Mines 2, 4,
and 6, have a large number of degas
options that provide better economic
performance compared to the base
case.
• The least gassy room and pillar mines
(Mines 3 and 5) are not identified
with economical degas options due
to the low volume of gas present in
this area. An estimated 1 to 6% in-
crease in coal production rate can
offset the cost of implementing the
degas system at these sites.
Region Specific Trends
• In general, this national assessment
suggests that investments in degas
and utilization systems yield higher
returns in the Warrior and Central
Appalachian regions than in any other
-------
Table 2. Summary of Results for the Most Promising Degas Technology Options
Incremental Economic Performance11
Gas Turbine Option
Pipeline Sales Option
Mine
No.
1 (base)
2 (base)
3 (base)
4 (base)
5 (base)
6 (base)
7 (base)
8 (base)
9 (base)
Coal
Mining Prod.
Region MMtpy
Warrior 1 .2
Warrior 2.4
Central Appal. 1.0
Central Appal. 1.8
North Appal. 1.0
North Appal. 3.0
North Appal. 3.0
Illinois 3.0
Western 3.0
Degas
Technology
None
HB
CVWC
GW/HB
GW/HB
CVWC
GW/HB/CVW
GW/HB/CVW
Glc
GW/HB/GIC
GW/HB/Gld
None
None
GW/HB
GW/HB
CVWC
GW/HB/CVW
GW/HB/CVW
Glc
None
None
GW
GW
HB
GW/HB
CVWC
cvwd
GW/HB
GW/HB
CVWC
GW
XM
GW/HB
GW/HB
CVWC
Estimated
Methane
Reduced3
%
0
25
99
0
28
32
45
71
42
81
48
0
0
49
58
67
99
71
0
0
37
38
61
83
46
0
36
51
0
32
0
33
28
NPV
(MM$)
0
0
30.31
32.86
13.35
14.78
9.09
0
0
23.52
25.51
12.81
14.81
1.20
0
0
7.59
10.34
12.45
7.44
3.45
0
3.6
2.77
0
0.03
0
2.79
9.76
Annual
Profit
(MM$)
0
0
4.58
5.53
3.65
4.46
4.01
0
0
3.72
4.47
3.34
4.55
3.07
0
0
1.17
1.69
2.50
2.73
1.33
0
0.90
2.04
0
0.20
0
0.79
1.80
IRR
%
0
0
38.10
31.2
16.7
15.6
13.3
0
0
32.9
28.3
17.1
15.4
10.4
0
0
35.4
31.2
21.5
14.3
14.0
0
17.4
11.8
0
10.2
0
16.0
26.3
NPV
(MM$)
0
0.24
8.88
0
39.46
43.81
37.82
55.09
9.09
25.01
7.48
0
0
25.22
29.09
20.28
33.25
0
0
0.98
0
0
0
Annual
Profit
(MM$)
0
0.24
1.67
0
5.26
6.46
5.74
8.18
3.99
6.10
3.60
0
0
3.39
4.34
3.31
5.14
0
0
0.29
0
0
0
IRR
%
0
11.1
25.3
0
75.6
49.3
40.8
45.3
13.3
18.1
12.1
0
0
72.2
47.6
33.2
39.2
0
0
15.6
0
0
0
a Emissions reduction for non-base case degas systems should be considered approximate (1) because the true effects of methane recovery on in-mine
methane liberation potential cannot be assessed, and (2) the volume of gas being vented is derived from straight accounting of the recoverable gas in place.
b Incremental Performance = option degas technology - base case technology.
c Degasification occurs in multiple zones.
d Degasification occurs in one zone only.
MMtpy = million tons coal produced per year.
MM $ = million dollars
GW = gob wells.
XM = cross-measured boreholes.
Gl = gas injection wells.
NPV = net present value at 10% discount rate of return.
IRR = internal rate of return.
HB = horizontal boreholes.
CVW = conventional vertical wells.
-------
region examined. This agrees with
the current practices employed at the
Warrior and Central Appalachian re-
gion mines.
• Both mines examined in the Warrior
Basin have several options for achiev-
ing better economic performance. The
pipeline sales option offers the high-
est return, primarily due to the large
quantity of gas utilized and the recov-
ery of pipeline quality gas which elimi-
nates expensive gas enrichment
equipment and operating costs.
• The large gassy mine in the Central
Appalachian Basin also has several
options which provide significant in-
crease in revenue with both gas tur-
bines and the pipeline option. The
pipeline option provides the highest
return due to the large quantity of gas
utilized and the recovery of high Btu
gas from the Pocahontas No. 3
coalbed.
• Gas turbines seem to be more profit-
able at the gassy mines in the North-
ern Appalachian Basin. The pipeline
sales option does not perform well
because all degas systems are as-
sumed to require gas enrichment be-
fore connecting into national trans-
mission lines. This significantly in-
creases the capital expenditure and
operating costs.
• Utilization of gas recovered from the
existing base case methane control
system in the Illinois Basin mine does
not offer positive economics, prima-
rily due to the low volume of gas
recovered.
• The Western region can utilize gas
turbines to achieve positive econom-
ics. The pipeline option is unprofit-
able due to high pipeline construction
costs.
Technology Specific Trends
• The analysis suggests that utilization
of gas recovered from existing base
case technologies offers high returns,
with usually the lowest additional capi-
tal costs and minimal changes in nor-
mal methane control practices.
Comparisons of the two methane end-
use strategies reveal that on-site
power generation with a gas turbine
generally provides better economic
performance than the pipeline sales
option if the pipeline option requires
gas enrichment. However, these re-
sults are highly dependent on the
mine's ability to utilize all power gen-
erated on site and selling any excess
power at the assumed rate of 50% of
the electricity purchase price.
Despite recovering a significant vol-
ume of gas, the pipeline option used
at Mines 6 and 7 in the Northern
Appalachian Basin does not offer fa-
vorable economics, mainly because it
is assumed that all gas recovered
from the degas system requires gas
enrichment. The results improve dra-
matically if it is assumed that about
half of the recovered gas is of pipe-
line quality and does not require en-
richment.
Multi-zone conventional vertical wells
provide better economic performance
at seven of the nine mines examined.
This occurs as an outgrowth of the
significant volume of gas that can be
recovered from the three to six zones
typically degassed. This technology
usually requires significant capital out-
lay.
Multi-zone technologies do not offer
strong performance in areas where
little or no overlying/underlying gas-
bearing strata exist such as in the
Illinois Basin (Mine 8).
The developmental gas injection pro-
cess is expected to offer significant
emission reductions, but is burdened
with high capital and operating costs.
In spite of these advantages, the tech-
nology offers higher return at Mines 2
and 4 in the Warrior and Central Ap-
palachian Basins, respectively. Due
to the developmental nature of this
technology, the performance and eco-
nomic results should be viewed with
caution.
Other Issues
• Barriers to coalbed methane devel-
opment relate to the characteristics
of the coal mining industry itself. Meth-
ane recovery projects often require
significant capital investments which
may not be forthcoming in times of
declining profits, as experienced by
the industry in recent years. Also,
most coal companies place highest
emphasis on coal production, limiting
investment in coalbed methane re-
covery. Finally, given the uncertainty
in the stability of future coal markets
and declining natural gas sale prices,
companies may be reluctant to invest
in coalbed methane recovery.
• Legal issues over the ownership of
coalbed methane resources are one
of the most important barriers to
coalbed methane recovery. Conven-
tional gas and oil rights for the same
tract of land are easily separated from
mineral (coal) rights according to
strata. However, there is no clear geo-
logical separation for coalbed meth-
ane resources. It is not generally clear
whether the owner of the coal rights
is also the owner of coalbed methane
rights. This problem is recognized,
and the U.S. Congress passed
coalbed methane ownership legisla-
tion as part of the Energy Policy Act
of 1992. This Act requires states to
develop a statutory ownership pro-
gram, or accept a mechanism that
allows coalbed methane development
to proceed in the absence of such a
program by pooling coalbed methane
interests (using an escrow account)
until such time as ownership is re-
solved. In addition, recent court deci-
sions indicate that a consensus is
emerging that coalbed methane re-
sources belong to the owner of the
coal rights. However, on federal lands,
most decisions have favored the oil
and gas lease holder.
-------
S. Masemore, S. Piccot, and J. Lanning are with Southern Research Institute,
Chapel Hill, NC 27514.
David A. Kirchgessner is the EPA Project Officer (see below).
The complete report, entitled "National Assessment of Environmental and Eco-
nomic Benefits from Methane Control and Utilization Technologies at U.S.
Underground Coal Mines," (Order No. PB98-118144-; Cost: $35.00, subject to
change) will be available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: 703-487-4650
The EPA Project Officer can be contacted at:
Air Pollution Prevention and Control Division
National Risk Management Research Laboratory
U. S. Environmental Protection Agency
Research Triangle Park, NC 27711
United States
Environmental Protection Agency
Center for Environmental Research Information
Cincinnati, OH 45268
Official Business
Penalty for Private Use $300
BULK RATE
POSTAGE & FEES PAID
EPA
PERMIT No. G-35
EPA/600/SR-97/152
------- |