Abstract
Coalbed methane (CBM) production is somewhat complicated and has led to
numerous methods of approximating production performance. Many CBM reservoirs
go through a dewatering period before significant gas production occurs. The
production process, with dewatering, adsorption of gas in the matrix and
molecular diffusion within the matrix, can be difficult to model.
Several authors have presented different approaches involving the complex
features related to adsorption and diffusion to describe the production
performance for coalbed methane wells.
Various programs are now commercially available to model production performance
for CBM wells, including reservoir simulation, semi-analytic and empirical
approaches. Programs differ in their input data, description of the physical
problem and calculation techniques. This paper presents comparative results of
several available programs using different test cases (vertical fractured wells
and horizontal wells).
Introduction
The flow mechanics of coalbed methane (CBM) production have some similarities
to the dual porosity system. Figure 1 compares the actual reservoir and its
idealization model where the matrix and the cleat systems can be
differentiated. Also, three sets of normal parallel fractures are shown (face
cleats, butt cleats and bedding plane fractures).
CBM models are characterized as a coal/cleat system of equations. Most of the
gas is stored in the coal blocks. Gas storage is dominated by adsorption
according with Equation (1).
Equation 1 (available in full paper)
Adsorbed gas content, Gc, is calculated with the Langmuir equation,
as follows:
Equation 2 (available in full paper)
Gas desorbs in the coal block and then drains to the fracture system by
molecular diffusion (Fick's law rather than Darcy's law). The drainage rate
(Fick's law) from the coal block can be expressed using Equation (3):
Equation 3 (available in full paper)
For Equation (3), q* represents drainage rate per volume of reservoir. For CBM
reservoir modelling, sorption time is related to the transfer shape factor, σ,
and the diffusivity term, Dc. Sorption time, τ, expresses the
diffusion process by means of Equation (4):
Equation 4 (available in full paper)
By definition, τ is the time at which 63.2% of the ultimate drainage occurs
when maintained at constant surrounding pressure and temperature.
The typical production profile for a CBM well is shown in Figure 2. The
production behaviour exhibits only water production from the cleat system at
the beginning (flow through the cleat system is governed by Darcy's law). Then,
due to the reduction in formation pressure, gas starts to desorb from the
matrix creating a concentration gradient, and gas and water flow through the
cleat system. The water rate decreases and the gas rate increases until the gas
peak is reached (the gas production behaviour in this stage is dominated by
diffusion). Finally, when depletion in the reservoir is significant, the gas
rate declines.
Several authors have presented different approaches to describe the production
performance for coalbed methane wells. Zuber et al.(1) pointed out
that history matching analysis can be used to determine CBM reservoir flow
parameters and predict performance by using a simulator modified to include
storage and flow mechanisms.
© 2009. Petroleum Society of Canada (now Society of Petroleum Engineers)
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History
- Original manuscript received:
26 March 2007
- Meeting paper published:
12 June 2007
- Revised manuscript received:
17 February 2009
- Manuscript approved:
4 March 2009
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