Summary
Coalbed methane now accounts for a significant fraction of domestic
natural-gas production. Injection of carbon dioxide (CO2) into coal seams is a
promising technology for reducing anthropogenic greenhouse-gas emissions and
increasing ultimate production of coalbed methane. Reservoir simulations are an
inexpensive method for designing field projects and predicting optimal
tradeoffs between maximum sequestration and maximum methane production. Optimum
project design and operation are expected to depend on the anisotropy of the
permeability along the face-cleat and butt-cleat directions, the spacing
between cleats, and the sorption isotherms for methane and CO2.
In this work, a dual-porosity coalbed-methane simulator is used to model
primary and secondary production of methane from coal for a variety of coal
properties and operational parameters. It is assumed that the face and butt
cleats are perpendicular to each other, with horizontal wells parallel to one
type of cleat and perpendicular to the other. The well pattern consists of four
horizontal production wells that form a rectangle, with four shorter horizontal
wells centered within the rectangle. In the limiting case of no permeability
anisotropy, the central wells form a “plus” sign within the square of
production wells. All wells are operated as producers of methane and water
until a specified reservoir pressure is reached, after which the central wells
are operated as injectors for CO2. Production of methane continues until the
CO2 concentration in the produced gas is too high.
The simulation results predict the optimum lengths of the injection wells
along the face- and butt-cleat directions and show how these optimum lengths
depend on the permeabilities in the two directions. If the cleat spacing is
sufficiently small, and diffusion of the gas through the pores to the cleats is
sufficiently rapid, instantaneous sorption may be assumed. Otherwise, the field
performance depends on the diffusion-time constant that characterizes the rate
of transfer between the cleats and the coal matrix. The pressures at which the
injection wells are operated also affect the amounts of CO2 sequestered through
the pressures and volumes of the sorption isotherms.
Introduction and Background
Increasing concentrations of greenhouse gases may be leading to changes in
the Earth’s climate. A rise in the globe’s average temperature is expected,
among other consequences. The main anthropogenic greenhouse gas is CO2. The
concentration of CO2 in the atmosphere is increasing continuously; therefore,
many countries have pledged to reduce, by 2010, the emissions of greenhouse
gases up to 8% relative to levels pertaining to 1990. Consequently, CO2 must be
captured and stored. Among storage options, the underground storage in depleted
oil and gas reservoirs and unmineable coals is considered to have the most
favorable economics. This option is also expected to have a low environmental
impact. Several federal agencies have major programs for CO2
sequestration.
Unmineable coal seams are a very attractive potential storage medium for
CO2. The injection of CO2 in coalbeds may be the most efficient option of all
storage possibilities if, while CO2 is stored, the recovery of coalbed methane
is improved. The process of displacing the remaining methane by CO2 after the
primary production of methane is referred to as enhanced coalbed methane
(ECBM). Carbon dioxide/ECBM technology and implementation were inspired by CO2
solvent flooding, one of the most successful enhanced-oil-recovery methods in
the U.S. and worldwide. The worldwide CO2-sequestration potential by use of
ECBM has been estimated at 150 Gt of CO2. A relatively small but significant
sequestration potential of 5 to 15 Gt may be profitable, generating net profits
estimated at U.S. $15/t for the most favorable cases.
A joint U.S. Dept. of Energy (DOE) and industry project has been initiated
to study the reservoir mechanisms and field performance of CO2 sequestration in
the world's first experimental (pure) CO2/ECBM recovery pilot, the Allison unit
field, operated by Burlington Resources. Initially, the pilot was intended to
test CO2/ECBM, but in time it evolved into a CO2-sequestration project. The
pilot consists of four CO2-injection wells and nine methane-production wells,
drilled on 320-acre spacing. The Allison unit CO2/ECBM shows that methane
production has been enhanced by CO2 injection and that CO2 has been
sequestered. In this project, vertical wells are used for both production and
injection. However, it has been shown that horizontal wells can increase
CO2-injection rate and improve aerial sweep, which can lead to more-favorable
flood economics. The sweep advantage is greatest in thin formations with wide
well spacing, such as coal seams in the eastern United States. Consequently,
the U.S. Dept. of Energy is cofunding a 7-year CO2-sequestration/ECBM project
that uses horizontal injectors and producers. The well pattern used in the
present study was suggested by the pattern chosen for that project.
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
16 February 2004
- Revised manuscript received:
22 December 2004
- Manuscript approved:
28 December 2004
- Version of record:
15 April 2005
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