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.