COALBED METHANE-CONCLUSION COALBED METHANE DEVELOPMENT FACES TECHNOLOGY GAPS

Richard A. Schraufnagel, Richard A. McBane
Gas Research Institute
Chicago

Vello A. Kuuskraa
ICF Resources Inc.
Fairfax Va.

The coalbed methane industry has grown rapidly during recent years, powered greatly by new science and better technology. Still, major challenges remain that require research and fresh ideas, particularly for developing new basins, deeper coals, and geologically complex settings.

This concluding article in a series of nine on coalbed methane that began Oct. 9, 1989, examines the major technology and research needs and the problems that still face the industry.

Successful research and development on these major topics will lead to a stronger, more geographically diverse and efficient coalbed methane industry and will add new supplies of clean-burning natural gas for use by consumers.

A LOOK BACK

In the 1970's, the U.S. Bureau of Mines and U.S. Steel started the landmark research and development project in coalbed methane, the five-spot pilot test in the Warrior basin, Ala.

The Bureau of Mines, and subsequently the Department of Energy, expanded this initial pilot test into a 23-well demonstration project at the Oak Grove mine site. This early research demonstrated that a major portion (73%) of the in-place methane resource could be produced with vertical wells and that the coal cleat and natural fracture systems inherent in coals would enable vertical wells to efficiently drain a substantial area.

With the Gas Research Institute's (GRI) entry into coalbed methane in the early 1980's, rigorous testing and analysis began to explain the numerous mechanisms that governed the storage, release, and efficient production of coalbed gas. A major field laboratory is now in place at the Rock Creek site, just a few miles north of the original Oak Grove pilot and demonstration sites.

Fig. 1 (with projection) shows the production research wells and the offset monitor wells at this field laboratory site. To date, several notable results have been achieved by this project:

The first objective of developing technology for multiply completing several coals within a single well bore has been achieved. Operators in the basin now routinely complete three coal zones per well; indeed, one operator is planning to complete, stimulate, and produce five distinct coal zones with a single well bore.

A second objective, pursuing new well test and reservoir diagnostic technology appropriate for coals, has led to the development of pressure transient "slug" tests along with instrumentation and software used for interpreting these tests (STEP test; see OGJ, Oct. 30, 1989, p. 70); the introduction of a coalbed methane reservoir simulation model, COMET-PC; and the development of other tools and techniques needed by the coalbed methane reservoir engineer.

Careful prestimulation and poststimulation analyses along with visual observations in mine-through experiments have advanced the understanding of hydraulically fracturing coals. The technologies and procedures for multiply stimulating a series of thin coals with a single stimulation was instrumental in enabling this type of coal resource to become economically producible in the Warrior basin. Fig. 2 shows hydraulic fracture geometry in relation to Black Creek group coal seams.

For the western U.S. coal basins, GRI has developed other technical products, particularly innovative geological techniques for identifying the more permeable "sweet spots" within a basin. Published reviews of GRI's various research projects and accomplishments are available from GRI in the Quarterly Review of Methane from Coal Seams Technology and in topical reports by its research contractors.1

A LOOK AHEAD

While much has been accomplished by coalbed methane R&D, many challenges still remain to be addressed by research and new technology.

Broadly speaking, these challenges can be grouped into six general areas:

Measuring and understanding permeability in coal seams

Finding the highly permeable, productive spots in a new coal area or basin

Predicting gas production and reserves and optimizing field development
Conducting well completions and stimulations in new and more complex coal settings

Reducing the costs of coalbed methane production
Overcoming or mitigating the environmental impacts of coalbed methane development

UNDERSTANDING PERMEABILITY

Establishing the correct permeability of coal-a fractured, multi-porosity reservoir-has been, and remains, a major challenge. Routine laboratory-based procedures on small plugs fail to capture the influence of cleats, joints, and natural fractures-the main paths of gas and water flow in coals.

Traditional well tests, such as drawdown or build-up tests, are hampered by the two-phase flow and gas desorption and reabsorption conditions present in coal. Even the specially designed STEP tests for coal seams generally indicate lower permeabilities than suggested by subsequent gas and water production.

When high skin factors (indicating well damage) are noted, there is little correlation between the permeabilities measured in a well test and those subsequently seen by gas and water production. Clearly, improved testing procedures and analytical tools are needed to reliably establish the permeability of coal seams.

A second critical research topic in this area is the relationship of permeability, depth, and long-term gas production. Previous research has suggested that because of coal's high inherent compressibility, its permeability decreases rapidly with depth of burial and with gas and water production as the pore pressure in the coal decreases relative to the overburden pressure.

The current understanding of the depth-permeability relationship is indicated by the line labeled "existing theory" in Fig. 3 which shows a rapid decline in coal reservoir permeability with increasing depth.2 However, drilling and testing in the deeper coals of the Warrior basin and in other basins reveal much higher permeabilities at depth than predicted by the "existing theory" and a simple depth-permeability relationship.

New data indicate that the depth-permeability relationship is in fact more complex and greatly influenced by localized in situ stresses and by permeability enhancement. A revised understanding of depth vs. permeability is required to explain that 11 enhanced permeabilities"

two orders of magnitude higher than previously expected for deep coals are indeed possible, as shown in Fig. 3. Should these new data prove to be broadly representative, the commercial potential of coalbed methane would increase substantially.

Preliminary laboratory investigations and reservoir modeling of changes in permeability with gas (and water) production indicate that, under certain conditions, the reduction in permeability because of pore volume compressibility may be more than offset by an increase in permeability due to matrix shrinkage as methane desorbs from the coal surfaces .3

As illustrated in Fig. 4, the 15% reduction in the peak gas rate due to the negative effects of pore volume compressibility are counterbalanced by a 60% increase in the peak gas rate due to the positive effects of increasing permeability from gas desorption and coal matrix shrinkage. (This analysis used a value of 4.5 x 10-5 psi-1 for pore volume compressibility and a value of 6.2 x 10-6 psi-1 for matrix shrinkage.)

While these initial findings on the nature of coal permeability are encouraging for the development of coalbed methane, particularly for deeper and tighter coals, many questions still remain to be addressed by research:

What factors govern the relationship of coal permeability with depth? How does gas desorption physically influence the coal matrix? How generalized, or alternatively, how coal specific are the depth-permeability and the matrix shrinkage phenomena?

How does the nature of the coal cleat and joint system influence the coal's relative permeability? Questions related to this are:

What is the critical gas saturation in this fractured system, and what establishes the residual water saturation for different coals?

To what extent can induced surfactants influence the shape of the relative permeability curve for the coal cleat or for the proppant pack?

Does measured permeability change with the radius of reservoir investigation for a fractured coal reservoir? What implications does this have on the proper length of time for conducting a well test?

What technological advances are required that would enable well logs to be reliably used for identifying enhanced permeability and in situ stress in coal seams?

FINDING IDEAL SITES

Much of the current exploration strategy for coals has centered on finding thick, gassy coals that are neither too deep nor too shallow. While adequate gas in place and pressure are important, sufficient permeability is critical.

Recently, research in the deeper western coal basins has emphasized finding the highly productive "sweet spot" portions of the coal basins. For this, some geologists are using remote sensing such as Landsat and other high-altitude photographic methods to identify surface geologic features that may indicate enhanced permeability. Others are looking for smaller-scale features such as folds and subtle flexures that may promote open coal cleats.

A third group is seeking the final areas of low stress and overpressuring as indicators of enhanced permeability.

The research questions to be addressed that would enable the identification of the "ideal spots" in a coal basin include:

Which set of natural fractures or tectonic events have created enhanced permeability (such as extensive open fractures), and which events have actually reduced permeability (such as highly stressed fault blocks)?

Does careful placing of wells on surface features or lineaments actually lead to superior wells?

How important is the maceral composition of the coal and the mineral composition of the coal/rock to the release of adsorbed gas and to long-term gas production?

PREDICTING PRODUCTION/RESERVES

Estimating gas productivity and reserves remains a major problem for producers of coalbed methane. The industry has yet to satisfy the financial community that it can reliably determine how much of the gas resource in a given area can be recovered and over what period of time.

Solving this problem will require three parallel R&D efforts: gaining a more rigorous understanding of the key gas production mechanisms; developing improved well testing and measurement tools; and introducing a more sophisticated reservoir simulation model that can accommodate multiple seams, nonuniform field patterns, and reservoir properties such as gas reabsorption.

The goal here is to enable operators to have as much confidence in estimating productivity and reserves in coalbed methane as they have, for example, in estimating waterflood oil recovery.

The main R&D objectives for better understanding coal seam gas production are establishing the nature of gas adsorption and desorption as well as fully defining the mechanisms affecting coal reservoir permeability. The major challenges in well testing R&D are properly establishing and accounting for the effects of two-phase flow and the larger scale effects of natural joints and fractures. The requirements for improved reservoir simulation capability are more numerous, as shown by Table 1 that compares the features of the existing reservoir model (COMET-PC) with the new reservoir model (COMET-PC 3D) being developed by ICF Resources with GRI support.

As additional reservoir data become available and new engineering tools are developed, researchers and developers will be able to address the many issues of optimum field and reservoir development. Here, the key research questions are:

What is the optimum well spacing for a basin, area, or formation from both a resource conservation and an economic point of view? How can the producer best make the trade-offs among well spacing, stimulation size, and production practices?

When coalbed methane recovery is linked to coal mining and methane drainage, how should a producer integrate predrilling and mine degasification for optimum methane recovery?

COMPLEX COAL SETTINGS

Numerous problems still exist in efficiently completing and stimulating coal seam wells. These problems include high treating pressures, fracture growth out of zone, and premature screenout. The research objectives in hydraulic fracturing are:

To understand the mechanisms controlling hydraulic fracture propagation in coal seams which can be incorporated into future fracture treatment designs.

To relate high treating pressures and premature screenouts to geologic or engineering parameters that can be determined in advance of the treatment.

To develop rules and procedures to modify treatment designs "on-the-fly" depending on the observed treating pressures.

The mine-through observation of stimulations in coal seams show that the induced fractures are more complex than previously thought. These observations show numerous parallel vertical fractures at the well bore, combination vertical and horizontal fractures (T-shaped fractures), and much wider, shorter fractures than expected.

A fundamental research program involving rock mechanics, fluid mechanics, and coal reservoir definition will be required to fully understand the many physical mechanisms influencing fracture propagation in coals.

Economic production from lower permeability coal seams will require longer, highly conductive hydraulic fractures. Improved well stimulation will need to go hand in hand with improved well completion. While recent research shows that perforated or slotted cased-hole completions provide improved control for a stimulation, other problems of fracture control and placement remain, particularly for situations where many thin coal seams are distributed across a large gross interval. Ultimately, optimum methane production from a basin will require well completions and stimulations specifically designed for the geologic and reservoir conditions encountered by the well.

COST REDUCTION

Commercial activity in the sweet spots of the Black Warrior and San Juan basins has provided initial data and understanding of the gas producing mechanisms. In these areas, the reservoir quality has been sufficiently high so that operators have been able to achieve commercial gas production by just applying or modifying existing tools and techniques.

As development moves to reservoirs of lower quality, improved technologies and lower costs will become increasingly important. Three areas that may have potential for cost reduction are reservoir evaluation procedures, water production and disposal, and on-site gas processing.

Currently, the only way to determine reservoir properties such as gas content and desorption of a coal seam is by coring and laboratory analysis. Methods to determine these properties by geophysical logging can help to reduce the costs and risks of development.

Cost-effective water treatment, particularly low-cost chemical precipitation or filtration technology, would enable much of the produced water that is currently marginally potable to be productively used for agriculture or by livestock, thus converting a production problem into a resource.

While coalbed gas is essentially pure methane, in certain settings the gas may contain carbon dioxide, nitrogen, or other contaminants. At present, the produced coalbed gas is commingled with natural gas or treated in central gas processing facilities. Lower cost, decentralized facilities, such as single-step CO2 rejection and dehydration and small-scale well site units, would be of particular value in new, geographically remote basins.

ENVIRONMENTAL R&D

Finally, a series of environmental issues, each requiring technologically innovative solutions, is of high concern to developers of coalbed methane. The most urgent are: the disposal or use of coproduced water and the pending regulations on air emissions for gas compression engines.

In general, coalbed methane wells must first be dewatered to achieve commercial rates of gas production. Thus, water disposal has become a major environmental issue in the Warrior, San Juan, and Appalachian basins.

In the Warrior basin, land application of the produced water is acceptable as long as the content of total dissolved solids (TDS) is less than 2,000 ppm, and water application does not cause erosion. In-stream discharge is allowed as long as the in-stream chloride concentration does not exceed 230 mg/l. of chlorides.

Dilution, aeration, and settling in ponds are often used to pretreat water before discharge.

A recent GRI study, "Biomonitoring of a Producer Water Discharge From the Cedar Cove Degasification Field, Alabama," has shown in-stream discharge to be environmentally safe.

An R&D program for efficiently disposing or using the produced coalbed methane waters would include the following:

Thorough chemical and constituents analysis of the produced waters would help guide water treatment and disposal efforts in each basin and coal formation.

Basin level hydrologic and biotoxicity research and integrated water gathering and disposal strategies could bring economics of scale, and thus major cost reductions, to the water disposal problem, enabling economically marginal wells to be developed.

For efficient desorption and gas recovery, coalbed methane wells need to be operated at low producing pressures requiring significant gas compression. The increasingly stringent controls on stationary emissions might limit the installation of compression at any one location.

Additional research into low NOx engines, advanced emission controls, and improved muffler design (for reduced noise) is needed.

The coalbed methane industry has progressed far in a short time. While research and innovative engineering have built the base of scientific understanding and demonstrated the essential production technology, much still remains to be done. Successful pursuit of this R&D will enable operators to more efficiently produce the known coal basins and to pursue the many challenging frontier coal basins.

ACKNOWLEDGMENTS

The authors would like to specifically thank Steven J. Jeu of McKenzie Methane and John A. Wallace of Taurus Exploration Inc. for their valuable insights on research and technology needs in the western and eastern coal basins.

The authors also thank the Gas Research Institute for its encouragement and contribution in preparing this article.

REFERENCES

"GRI Publications on Coalbed Methane," Quarterly Review of Methane From Coal Seams Technology, Vol. 7, No. 1 + 2, October 1989, pp. 13-26.

Koening, R.A., et al., Application of Hydrology to Evaluation of Coalbed Methane Reservoirs, GRI Topical Report, GRI-89/0031, March 1989, pp. 25-41.

Harpalani, S., "Permeability Changes Resulting From Gas Desorption," Final Report, GRI 89/0129, October 1989, pp. 55-59, 81-88.

O'Neill, P.E., et al., Coalbed Methane Development in Alabama, Biomonitoring of a Produced Water Discharge from the Cedar Cove Degasification Field, Alabama, Final Report GRI-89/0073, by Geologic Survey of Alabama and ENSR Consulting and Engineering, June 1989.