Abstracts

Coalbed Methane Potential in Osage County, Oklahoma

Sinclair, John F. VP - Exploration, AMVEST Gas Resources, Charlottesville, VA

Cherokee and Marmaton age host rocks contain numerous thin coal seams which are present within Osage County Oklahoma. Primary seams for exploration and development are the Rowe, Bluejacket, Weir-Pitt and Dawson seams. These seams are extremely thin as aggregate and as individual seams when compared to other CBM plays outside of the Mid-continent area. When present these seams range in thickness from a few inches up to 5 feet thick. The average individual seam thickness is less than 2 feet and rarely is there more than 12 feet of coal located within a single well bore. These coals are high-volatile A coals and in some instances grade into medium-volatile coals. Vitrinite reflectance values range from .85 to 1.1 and generally increase with depth.

Structurally, Osage County is located within the Northeast Shelf of Oklahoma. General dip is to the west, but there are numerous domes and NE-SW trending anticlines located in Osage County. Basement faulting is the primary mechanism for creating structural disturbance and many of these faults appear to be compressional features derived from movement originating in the Arkoma Basin.

AMVEST Osage has drilled 178 CBM wells since January of 2000. First production started in September of 2001. Current production as of October 1, 2004 was 10.5 MMcf/d. In addition to the drilled wells, 5 slim hole, continuous, wireline retrievable cores were drilled. The cores were used to evaluate the CBM resource through gas content measurements, adsorption isotherms and maceral analysis. Total resource calculated for the AMVEST concession in Osage County is in excess of 2.1 TCF. Numerous permeability measurements have been made within the coal seams of Osage County within cased wells and in the open hole core well bores. Permeability ranges from .2 md to in excess of 300 md. Initial exploration focused on thicker coal accumulations on structural highs or noses of anticlines in order to find higher permeability within the coals. This approach was not always successful and not all of the good producing wells are located on these structural highs. Currently, AMVEST is developing a structural model that will help predict areas of higher permeability.


Overview of Coal Gas Reservoir Properties of Western Interior Coal Region Research Coreholes

Simon Testa - Geologist, TICORA Geosciences, Inc.

TICORA Geosciences, Inc. collaborated with El Paso Production Company and Colt Energy, Inc. to collect detailed core datasets from samples collected in seven core holes located in the Western Interior Coal Region (WIC Region) of the North American Mid-continent. The cooperative research project, funded by the Gas Research Institute, included analysis of 197 canister desorption experiments collected from Middle Pennsylvanian coal and carbonaceous shale intervals in the Forest City, Cherokee, and Arkoma basins. Desorbed gas content, gas composition, gas storage capacity, and coal characterization data were measured. Analysis of these data resulted in three regional relationships between sorption properties and coal rank (i.e., thermal maturity):

This study offered the opportunity to characterized coal and sorption properties for numerous coal seams over a wide geographical area (85,000 square miles) that share similar depositional histories and that range widely in thermal maturity. However, as the density of core holes sampled over this large geographic area is low, caution is advised in applying these general regional trends to formulate decisions concerning the resource and production potential for the region.

This study also provides estimates of potential gas productivity for specific corehole locations based on estimates of absolute permeability and reservoir pressure. As these key reservoir parameters were not measured it is impossible to accurately predict the gas production potential from the data presented herein.


Coalbed Methane Production and Completion Optimization

Michael J. Miller, P.E., Marshall Miller & Associates, Inc.

Many companies have become involved in coalbed methane (CBM) exploration and production in recent years. Although the majority of these companies are established oil and gas operators, many have jumped into the play without CBM experience or input from those with it. They usually have reviewed publications that discuss CBM and seen presentations of increasing CBM production and numbers of wells, concluding that the opportunity is great. However, by failing to properly support development efforts with geologists, engineers and operations personnel that possess adequate CBM experience, returns on invested capital are often much less than could have been achieved.

The primary purpose of this presentation is to review some key factors that should be considered in CBM prospect selection and evaluation, and in optimizing well completions and production. Attention to the items discussed here should enable startup CBM operators to climb the learning curve more rapidly and perhaps delineate some techniques that will help established CBM operators improve project performance.

This presentation encourages CBM operators to address certain issues in greater detail with CBM professionals on their staffs or with experienced consulting firms. The goals are to enable drilling CBM wells in the most prospective areas, to minimize damage to good wells, and to ensure that wells produce at or near their potential.


Overview of Unconventional Gas Resources and Development

Vello A. Kuuskraa, President, Advanced Resources International, vkuuskraa@adv-res.com

In a span of 20 years, the outlook for unconventional gas resources has grown from modest expectations to a major source of domestic natural gas supply, now exceeding natural gas production from the offshore Gulf of Mexico. During this time, coalbed methane, one of the three primary unconventional gas sources, has changed from a scientific curiosity to providing, last year, over 1.6 Tcf (4.4 billion cubic feet per day) of pipeline quality natural gas. Looking forward to the next 20 years, unconventional gas is expected to become the largest single source of domestic natural gas supply, with growth in all three resources - - tight gas, gas shales and coalbed methane.

The presentation reviews the major progress in knowledge and technology that provided the foundation for the remarkable growth of this domestic natural gas resource. A particular focus will be placed on the development of the knowledge and technology base for coalbed methane and how continued progress in technology would further improve the economic viability of this key unconventional gas resource.


Unconventional Drilling Methods for Unconventional Reservoirs

Doug Wight, VP Corporate Development, CDX Gas, LLC

For a number of years, drilling technologies like gob wells, vertical drill and frac wells and basic horizontal wells have been employed to produce methane gas trapped in low-permeability reservoirs like coal and shale. While these conventional drilling methods are well suited for very porous coal deposits, they haven’t proven economically viable in low-permeability reservoirs because they don’t drain uniformly and typically have low production and recovery rates. In addition, these conventional wells usher in numerous environmental concerns with regard to surface disturbance and water disposal.

Without efficient, effective technologies, many operators deemed coal and shale reservoirs unviable prospects. However, recent advances in drilling technologies and demands for natural gas have given operators reason to re-evaluate the feasibility of developing unconventional gas reserves.

Dallas-based CDX Gas, LLC has developed the Z-Pinnate™ Horizontal Drilling and Completion System. This patented drilling and recovery technology dramatically enhances production in low-permeability coal and shale reserves by employing a multilateral, leaf-shaped (hence the name “Pinnate”) drainage network spanning 1,200 acres from one surface well site. By contrast, traditional drill and frac recovery methods require one well for every 80 acres of coal. The CDX system enables recoveries of 80 to 90 percent in a two- to four-year period, compared to about 20 percent gas recovery over 30 to 40 years for conventional wells.

A pinnate pattern unlocks gas trapped in low permeability rocks and allows wells to reach maximum production rates in a matter of days by minimizing the dewatering period. By reducing the number of wells needed to deplete a project area, the Z-Pinnate ä system reduces the surface disturbance caused by locations, gathering systems and production facilities. This technique also reduces project development costs, making recovering gas from unconventional reservoirs more economical and environmentally sensitive.


Coal Gas Origins and Exploration Strategies

Andrew R. Scott Altuda Energy Corporation, San Antonio, Texas andrew@altuda.com

Natural gas prices are expected to remain relatively high over the next two to five years and these higher gas prices have turned coalbed into one of the most active gas plays in the United States. Coalbed methane is an important part of the natural gas supply for the U.S. and now represents more than 8 percent of total gas production and 9 percent of dry gas proved reserves and these values are expected to increase. Exploration for coalbed methane in remote or frontier regions is often hampered by the absence of an adequate data base which inhibits detailed evaluation of coalbed methane exploration potential. However, exploration strategies can be developed or refined based upon, coal gas and formation water compositional and isotopic data collected during early exploration.

Any combination of four basic types of coal gases (or any combination of these types of coal gases) may be present in a coal bed: (1) thermogenic, that include early thermogenic and main-stage thermogenic, (2) secondary biogenic, (3) migrated thermogenic or secondary biogenic, and (4) indigenous thermogenic or biogenic. Areas of highest gas content are often associated with upward flow potential and the most effective conventional and hydrodynamic traps are perpendicular to migration pathways. Therefore, exploration strategies can be based upon gas chemistry and inferred coal gas origins, and inferred migration pathways using a hydrologic approach to coalbed methane exploration. For example, if the formation waters are saline, then the types of coal gases will probably be early thermogenic or thermogenic (depending on coal rank). . Thermogenic gas contents are highly variable, but may have very high values exceeding 600 scf/ton. If the coal gases migrated updip, then exploration targets should be on the downdip side of potential permeability barriers or on structural highs and even synclinal axes where higher permeability might exist.

If the formation waters are fresh or brackish, then methanogenic and other microbes may have been transported basinward through permeable coal beds after the basin was uplifted and cooled. These microbes can bioconvert the coal and organic compounds generated during thermal maturation into secondary biogenic gases. Secondary biogenic gases may occur in coals of any rank ranging from lignite to anthracite. The process of secondary biogenic gas generation is not trivial since up to 2 Tcf of gases produced from the San Juan Basin are secondary biogenic and nearly all of the gases in the Powder River Basin are biogenic. Gas contents associated with secondary biogenic processes in low rank coals are generally low (less than 40 scf/ton). Exploration targets should be on the updip side of permeability barriers or on structural highs if secondary biogenic gases are the dominant gas type in low rank coals.


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Last Modified October 2004