G A L E A N D F R E U N D : C O A L - B E D M E T H A N E E N H A N C E M E N T 211
that contained in a conventional, sandstone gas reservoir of
comparable size.
within the reservoir, which could alter this ratio. Early indica-
tions from actual applications suggest this ratio might be
higher (three or more) depending on channeling of CO2
through faults and other high-permeability pathways.
Coal-bed methane (CBM) is conventionally recovered by
means of reservoir pressure depletion, which is a simple but
inefficient process recovering typically only 50% of the gas
in place. Hydraulic pressure is used to assist recovery but,
even so, because permeability is normally low, many wells
must be drilled to achieve adequate gas flow. The methane
removed directly from coal beds is generally of high purity
(in excess of 90%), particularly where it is recovered from
seams that have never previously been mined. In many
cases it could be supplied directly to a natural gas distribu-
tion system, if convenient. In other cases, it could be used
for power generation, heating, or sold to third parties.
During the past two decades, operators in the United
States have successfully adapted oil field technology to pro-
duce methane from deep coal seams. Investment of more
than $4 billion has achieved annual production in 1996 of
28 million m3 from over 6,000 coal-bed methane wells, ac-
counting for 5% of total U.S. natural gas production
(Stevens et al., 1996). Outside the United States, interest in
coal-bed methane production is also growing.
The depth “window” for CO2-ECBM is expected to be
the same as that for CBM production (300 to 1500 m). CO2-
ECBM is likely to be less attractive in areas of high coal
permeability from a CBM production prospective, although
CO2 sequestration alone would be effective. It is felt that
ECBM might work more effectively than pressure depletion
in areas with low to medium porosity. This was one reason
for Amoco’s placement of N2-ECBM project in a part of the
San Juan basin with much lower permeability than the more
favorable areas in the basin.
The production increase due to CO2 injection takes longer
to develop than when using N2-injection (Figure 1). This is
due to the absorption of CO2 relatively near the well with
the absorbed CO2-CH4 front growing elliptically out from
the injection wells. After a sufficient volume of methane has
been displaced, the methane productivity increases. Eventu-
ally, significant concentrations of CO2 will be present in the
produced gas at the production well and most probably the
project would then be terminated. It is noted that in CO2-
EOR production, CO2 concentrations in the product can be
high at an early stage, and the CO2 is separated from the
produced oil and reinjected. In this case, CO2 sequestration
in the oil can continue despite early CO2 breakthrough.
CO2-ECBM, therefore, is potentially capable of providing
storage for anthropogenic CO2 as well as improving the pro-
duction of coal-bed methane. If the coal is never mined, it is
likely that the CO2 would be sequestered for geological time
scales. However, if the coal were disturbed, this would void
any potential for CO2 storage and so the fate of the coal
seam is a key determinant of its suitability for sequestration.
The Alberta Research Council (ARC) in Canada is inves-
tigating an alternative approach using flue gas or combined
N2-CO2 injection. With N2 injection early N2 breakthrough
at the production well causes additional operational costs
because the N2 must be separated from the methane before
sale. Combining CO2 and N2 injection will improve the eco-
nomics because the appearance of N2 will be retarded com-
pared to N2 injection alone, and the methane production rate
will be increased by the addition of CO2. To date, however,
there is little experience of injecting flue gas into geological
formations. The ARC has now performed a single-well mi-
cro-pilot test with flue gas injection, the results of which are
now being evaluated (Wong and Gunter, 1999).
CO2-ENHANCED COAL-BED
METHANE
Recently, new technologies have been proposed for en-
hancing coal-bed methane (ECBM) production (Murray,
1994; Wong et al., 1998). The two principal variants are in-
ert gas stripping using nitrogen injection, and displacement
desorption employing carbon dioxide (CO2) injection.
Simulation and early demonstration projects indicate that
nitrogen injection ECBM (N2-ECBM) is capable of recover-
ing 90% or more of gas in place in the coal seam. N2-ECBM
works by lowering the partial pressure of methane to pro-
mote desorption. Nitrogen injection rapidly increases meth-
ane production rates. The timing and magnitude depends on
the distance between the injection and production wells, the
natural fracture porosity, and permeability and the sorption
properties. N2 breakthrough at the production well occurs
rapidly. The N2 content of the produced gas continues to in-
crease until it becomes excessive (i.e., 50% or greater) when
injection would probably be halted (Figure 1).
In the CO2-ECBM process (Figure 2), injected CO2 is pref-
erentially adsorbed at the expense of the coal-bed methane,
which is simultaneously desorbed and can then be recovered
as free gas. The CO2 remains stored within the seam provid-
ing the seam is never disturbed. Laboratory isotherm mea-
surements demonstrate that coal can adsorb roughly twice as
much CO2 by volume as methane; the working assumption is
that the ECBM process stores 2 moles of CO2 for every 1
mole of CH4 desorbed. However, the physical chemistry of
this process has not yet been fully defined and there remains
the possibility that there are other physical processes active
CURRENT TECHNICAL STATUS
OF CO2 SEQUESTRATION IN
COAL SEAMS
In the late 1980s Amoco Corporation, through a series of
patents and numerical simulations, developed the concept for