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The presence of methane in coalbeds has been recognized for hundreds of years, primarily
as an explosion and fire hazard in the mining of coal. Initially, efforts to extract
methane from coal were limited to attempts at improving coal mining safety. However,
within the past decade, the energy potential of coalbed methane has begun to be explored,
and production has increased rapidly to the current level of approximately 7.5% of the total
U.S. natural gas production. Current estimates from the U.S. Geological Survey
postulate a total of 85 TCF (trillion cubic feet) of recoverable gas from fifteen of the more
promising geologic provinces in the United States alone.
Methane, which typically accounts for 95% of the gas contained in coal, is retained within
coal in one of three states: as adsorbed molecules on the internal surfaces and within
the structure of the coal, as gas trapped within the pores or fractures of the coal, or in
solution within the groundwater that may exist within the fracture system.
Of the three mechanisms of methane storage, adsorbtion within the coal itself accounts for
most of the methane found within a coalbed. Methane adsorbed within the coal can be
released by lowering the pressure within the coal. This can be done by removing water
from the coal, which disturbs the equilibrium that exists between the methane adsorbed within
the coal and that existing in the fracture system. This reduction in pressure results
in the diffusion of methane from the matrix of the coal into the fracture system, and then a
flow of the gas and water into the wellbore.
Typical coalbed methane wells display a distinctive pattern in gas production over time.
During the dewatering stage, water is removed to lower the pressure within the coalbed.
CBM wells within some geologic basins, such as the Powder River and Warrior basins,
produce very little gas during dewatering. Others basins, such as the Cherokee and
Appalachian basins, begin to produce some gas almost immediately. Once the water
pressure is removed during the dewatering stage, production stabilizes with peak gas
production and minimal water production. As a CBM well is entering the end of its
production, methane production gradually declines. This pattern of gas production in
a typical CBM well is displayed below:
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The economic viability of a CBM play is determined by three main factors: the gas
content of the coal, the permeability or flow characteristics of the coals, and the thickness
of the coal beds. Operators can enhance the permeability of a coalbed by introducing
artificial fractures into the coal, and this induced fracturing is part of most CBM well
completions. The other two factors determining gas production are more limiting.
Gas content within the Cherokee Basin of Southeastern Kansas can range up to 330
scf/ton, with economic production from seams as thin as 0.5 feet thick. Some coal seems
in the Cherokee Basin reach up to 5 feet in thickness.
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