ارزیابی Coalbed-Methane
Because of the complexity of coal reservoirs, formationevaluation
techniques are extremely important for determining
the commercial viability of coalbed-methane
prospects. This article focuses on the reservoir evaluation
techniques that are used to assess prospects for coalbedmethane
development. A variety of reservoir-evaluation
methods specific to coal reservoirs have evolved over time,
including core evaluation, well logging, seismic, transientpressure
testing, and production analysis. This article
addresses current methods and newer, state-of-the-art
methods that are under development and becoming more
accepted for use in evaluating coal reservoirs.
As Fig. 1 shows, coals are complex, naturally fractured
reservoirs. Coalbed-methane production is characterized
by a high degree of variability. This variability in well production
exists when comparing wells within discrete production
fields, across regions within producing basins, and
between coal basins. Lateral changes in reservoir permeability
appear to be the primary cause of well-to-well production
variation, although changes in coal-seam thickness,
sorbed gas-content, water saturation, and reservoir
pressure also affect well productivity.
Many coalbed-methane prospects are under evaluation
in the U.S. and throughout the world. In the U.S., higher
gas prices have accelerated exploration of prospects in
areas that previously were thought to be uneconomical for
development. These areas include relatively unexplored
new basins as well as step-out areas in developed production
areas. In addition, significant prospect evaluation is
occurring in international areas, including Australia,
China, India, and Europe.
Objectives of the Reservoir Evaluation
From the reservoir-evaluation standpoint, two main questions
must be addressed: What is the resource in place? And
what are the production characteristics of the reservoir?
Before discussing these questions, it is worth noting that
reservoir evaluation for coal reservoirs must be performed
on a field-by-field basis to develop a proper understanding
of the production characteristics and reserves for each area.
This requirement results from the inherent variability of
the coal reservoir, which is born out by historic producing
trends in mature development areas, such as the Black
Warrior basin in Alabama (Fig. 2) and the San Juan basin
in Colorado and New Mexico (Fig. 3). Also, it is important
to understand this variability when evaluating pilot-project
or exploration-test data while attempting to evaluate the
commerciality of prospective development areas. Because
of the inherent variability in production, it is often difficult
to evaluate commercial viability on the basis of a few random
data points. Often, multiple exploration wellbores
and/or pilot tests are needed to understand fully the
expected average production and reserves for a prospective
development area.
Volume of the Gas Resource in Place. Estimating the
resource in place depends upon the following reservoirparameter
determinations.
• Reservoir geometry (depth, thickness, lateral extent,
number of seams, and structure).
• Gas content (both sorbed and free gas).
• Coal composition (chemical, maceral, and mineralogical).
Three methods are used to determine these properties:
well testing, core testing, and seismic. Well logging is primarily
used to evaluate reservoir geometry and coal thickness.
The basic logging suite for evaluating coal reservoirs
includes gamma ray, density, resistivity, and caliper tools.
Neutron logs also are run in many cases. The density log
(especially when run in a high-resolution format) is most
useful for evaluating reservoir thickness because of the
large inherent differences in density between coals and the
surrounding rock layers. However, similar results can be
obtained by use of the appropriate resistivity and neutron
logs. Importantly, the high-resolution density log can be
evaluated to determine the volume of noncoal material
(primarily mineral-matter) in the target coal seam. Resistivity
tools can be useful in some cases for estimating relative
differences in reservoir permeability in multiseam
reservoirs because of fluid invasion into the naturally fractured
coal reservoir. Image logs are used sometimes to
assist in this evaluation of cleat and fracture characteristics.
Newer state-of-the-art chemical logs are beginning to be
used to identify basic chemical components in the coal
reservoir, which then can be reconstructed to give a logbased
coal compositional analysis. When calibrated with
core data, these tools can be used to evaluate the relative
quality of multizone reservoirs and assist in designing well
completions. Importantly, these tools are permitting a
more detailed analysis of coal seams present behind pipe in
wells that had previously targeted other hydrocarbon reservoirs.
Fig. 4 shows a sample well-log evaluation.
Core recovery and testing remains the primary method
for evaluating gas resource in place in coal reservoirs.
Three main tests include the canister desorption test for
direct measurement of the volume of gas in the recovered
coal core, the laboratory sorption analysis for determining
the coal isotherm (relationship between pressure and sorptive
capacity), and the proximate analysis for defining
basic coal composition (primarily ash and moisture content).
These parameters define the basic gas-in-place per
unit of reservoir mass, as well as how the gas will be
released upon pressure reduction in the reservoir. Because
these parameters can be measured from only fresh coal
samples, coring still remains a large part of the reservoirevaluation
process.
Seismic data can be useful in determining reservoir
extent and structure. Primarily, seismic investigation has
been used in virgin exploratory areas where subsurface
data control is limited. Historically, seismic data were not
used extensively for the evaluation of coal reservoirs.
Many of the early coalbed-methane projects were in areas
that have abundant subsurface data. These data were either
from underground mining activity and mine-development
coreholes (such as the Black Warrior basin) or from geophysical
well-log data in areas of significant oil and gas
activity targeting other formations (such as the San Juan
basin). As the industry moves into areas with little or no
subsurface data, seismic-data acquisition and evaluation
becomes more important. In addition, with improvements
in processing seismic data (such as shear-wave
anisotropy), regions of enhanced natural fracturing of the
coal seam (and higher permeability) may be identified.
Production Characteristics of the Reservoir. The primary
parameters in determining the production characteristics
of the reservoir are as follows.
• Desorption characteristics (isotherm).
• Permeability.
• Gas saturation conditions.
•Well spacing.
• Reservoir pressure.
Productive characteristics of coal reservoirs depend primarily
upon the reservoir permeability and the initial gassaturation
conditions in the reservoir. The primary evaluation
methods include well testing, production logging,
analysis of production-test data, and material-balance
techniques.
Well testing is the primary method for evaluating
reservoir permeability, and single-phase water
injection/falloff testing is the most popular
method. This method is the most versatile in evaluating
permeability across a wide range of reservoir
conditions. Other test methods, such as conventional
drillstem tests and slug tests, also have
been used to evaluate coal permeability. However,
these methods have limitations that make their
use viable only under certain conditions. Often,
well tests provide the most accurate estimates of
initial reservoir pressure.
In evaluating multizone coal reservoirs, it often
is important to develop a relative comparison
between the production characteristics of the different
potential target zones. This comparison is
accomplished best by combining production logging
with an injection test. Because most coal
reservoirs will not flow gas or water to the surface
naturally, it generally is not possible to run production
logs under flowing conditions. Therefore,
an injection test can be used as a “reverse” production
test, and a production log can be used to define
the relative flow contributions of the various zones and
assist in determining completion methodologies in multizone
reservoirs.
Perhaps the most widely used analysis method is production
analysis. Before large-scale commercial development,
most coal reservoirs are evaluated by use of some
type of production test, be it a pilot test or a small-scale
demonstration project for a period of 1 to 6 months.
These initial production data provide an indication of the
actual production characteristics of the reservoir under
field conditions. Analysis of the collected production data
usually requires the use of a coalbed-methane simulator
to characterize the complex coal-reservoir flow mechanisms.
Significant experience in this area has shown that
reservoir models calibrated with production-test data can
be extremely useful for estimating production characteristics
and reserves for coalbed reservoirs. The calibrated
models then are useful for optimizing completion and
production methods, as well as for optimizing development
well spacing.
Finally, material-balance methods have been developed
for coal reservoirs. These methods use standard materialbalance
equations, with the addition of coal desorption
equations. These methods have proved accurate in estimating
reserves for coalbed-methane reservoirs. However,
application of these methods requires accurate measurements
of reservoir pressure (at initial conditions and over
time), which often are not available.
Michael D. Zuber, SPE, is Principal Consultant—Unconventional
Gas with Schlumberger Holditch-Reservoir Technologies.
He is responsible for assisting clients in the evaluation
and optimization of unconventional gas reservoirs, such as
coals, shales, and tight sands. Zuber has authored numerous
papers and articles relating to the evaluation of coalbed
methane reservoirs. He is a registered professional engineer
in Pennsylvania and holds a BS degree in petroleum engineering
from Marietta College and an MS degree in petroleum
engineering from Texas A&M U. Charles M. Boyer II,
SPE, is Principal Consultant with Schlumberger Holditch-
Reservoir Technologies. In the area of coalbed methane, he
has authored more than 70 technical papers and articles and
has made more than 50 technical presentations at conferences
throughout the world. Boyer’s current focus is reservoir
assessment methodology, as related to coal-seam reservoirs.
He holds a BS degree in geological sciences from Pennsylvania
State U. and has completed graduate studies in mining
and petroleum engineering at the U. of Pittsburgh and Pennsylvania
State U.