Coalbed methane accounts for about 8 percent
of the natural gas produced in the United States. With global exploration
and development in an early phase, coalbed methane is poised to
continue for decades as an important energy source.
Coal also is a potentially important sink for greenhouse
gases like carbon dioxide (CO2), as well as other acid
gases such as sulfur dioxide (SO2) and hydrogen sulfide
(H2S). Sequestration of CO2 in coal is attractive
because coal has greater affinity for acid gas than for methane
Because of this, injection of CO2 and
other gases has potential not only to benefit the environment, but
to enhance coalbed methane recovery in much the same way that waterflooding
or CO2 injection can be used to enhance oil recovery.
With the promise of environmental benefits and enhanced
gas recovery come technical challenges that need to be confronted.
Among the greatest challenges for implementing sequestration programs
is developing economically feasible technology for separation of
acid gas at the source, and developing the infrastructure to transport
the gas to prospective sequestration sites.
The National Energy Technology Laboratory of the U.S. Department
of Energy has implemented a vigorous and diverse research and development
program to address these and a host of other geologic and engineering
issues that must be faced before CO2 sequestration can
be demonstrated at a broad scale.
Coal-fired power plants are significant sources of
CO2 and SO2, and separation technologies being
considered range from cryogenic and chemical separators to membrane
separators and pressure-swing adsorption units.
H2S is a hazardous waste product of oil
and gas fields, and chemical separation of H2S from hydrocarbon
streams is a long-standing practice. Once acid gas is separated
from the source, it can be transported by pipeline, truck or some
other method to where it can be injected into coal.
Although much of the technology required to inject
gas into coal already is available, a detailed understanding of
reservoir geology is indispensable for ensuring that the gas is
sequestered safely and effectively.
The geologic factors that must be considered for
sequestering acid gas in coal include stratigraphy, sedimentology,
structural geology, coal quality, basin geothermics and hydrology.
Stratigraphic and sedimentologic variables
are important because the thickness, continuity and geometry of
coal bodies are determined largely in the original depositional
Geologic structure is a fundamental consideration because faults
limit the continuity of coal, and fractures may pose risk for leakage
of injected gas from coal into the adjacent country rock or to the
Coal quality, specifically rank and grade, affect how much acid
gas can be sequestered in coal and the relative proportions of gas
that can be sequestered.
For individual gases, adsorption capacity increases
significantly with rank. Researchers at the U.S. Geological Survey
have confirmed that coal of bituminous rank can adsorb about twice
as much CO2 as CH4 at reservoir pressure,
and have discovered that sub-bituminous coal and lignite can adsorb
many times more CO2 than CH4.
Along these same lines, researchers at the University
of British Columbia have found that coal is an exceptional sorbent
for H2S and SO2, with adsorption ratios relative
to CH4 approaching or even exceeding 100:1 at low pressure.
Coal grade is important because the mineral constituents of coal
can adsorb only minimal amounts of gas relative to the microporous
Thus, coal with high ash content tends to have reduced
Hydrology and geothermics are significant
from the standpoints of water chemistry and phase relationships.
Fresh water is common in coalbed methane reservoirs, and current
regulations limit injection for enhanced hydrocarbon recovery to
formations with total dissolved solids content greater than 3,000
Phase changes occur for acid gases within the realm
of common reservoir conditions.
For example, the Alabama Geological Survey has determined
that about half of the coalbed methane wells in the Black Warrior
Basin had bottom-hole pressures and temperatures beyond the critical
point for CO2 prior to gas production. Understanding
phase relationships for CO2 is especially important,
because supercritical CO2 can react with and weaken coal.
Pilot programs for the injection of CO2
in coal have been conducted for a number of years in the San Juan
Basin of Colorado and New Mexico (BP-Amoco and Burlington Resources)
and in the western Canada foreland basin (Alberta Research Council).
These programs point toward success, and new pilot programs are
set to begin in West Virginia (CONSOL) and southern Poland (RECOPOL).
A key concern has been the reduction of permeability
by swelling of coal as CO2 is adsorbed. However, long-term
gas flooding in the San Juan Basin indicates that careful monitoring
of injection can result in sustained CO2 sequestration
and enhanced coalbed methane recovery.
As challenges are identified and overcome, a future
that couples environmental benefit with enhanced resource recovery