COAL BED METHANE DEVELOPMENT IN THE MIDCONTINENT AREA

Based primarily upon a workshop sponsored by PTTC's North Midcontinent Region on June 3, 1999, in Wichita, KS.

BOTTOM LINE

Numerous coals in the Pennsylvanian section of the Midcontinent area (encompassed by Kansas, Missouri, and Oklahoma) are appropriate to consider for coal bed methane (CBM) exploration. The number of potential targets, coupled with the region's industry experience in drilling and stimulation and its pipeline infrastructure, make CBM operations economically attractive.

PROBLEM ADDRESSED

Coal Bed Methane (CBM) activity has grown rapidly over the last decade in the Midcontinent region, but numerous opportunities remain for economic development of additional resources. Opportunities are waiting for operators who are willing to gather the information needed for identifying potential CBM reservoirs and willing to learn the technologies and techniques needed to produce them.

KEY WORDS:

Coal Bed Methane, ECBM, CO₂ Injection, Nitrogen Injection, Section 29 Tax Credits

SPEAKERS

Lawrence Brady, Kansas Geological Survey

Brian J. Cardott, Oklahoma Geological Survey

Lanny G. Schoeling, Shell CO₂ Company, Ltd.

Donald Schrag, Morris, Lang, Evans, Brock, and Kennedy

Kenton Hump, KLHConsulting

Steve Skaggs, Consolidated Industrial Service

TECHNOLOGY OVERVIEW

In Kansas, CBM activity concentrates in the eastern quarter of the state and is associated with Middle Pennsylvanian coals of the Cherokee Group. High volatile A bituminous coals predominate in the southeastern corner, grading to high volatile B bituminous in the east- central part of the state. Toward the northeast into the Forest City Basin, coals increase in rank. These ranks are based on chemical analyses and indicate a maturity slightly higher than that suggested by vitrinite reflectance.

Kansas has over 53 billion tons of deep (greater than 100 ft in depth) coal reserves contained in 32 identified coal beds. Only about two billion tons is found in beds more than 42 in. thick. Although coal seams are typically thin, a deterrent to commercial development of CBM, the cyclic nature of the deposits makes it possible to inter sect multiple coal seams in a single well. In the Forest City Basin in northern and northwestern Missouri, a surface area of more than 24,000- square mi contains Pennsylvanian sediments with 40 identifiable coal beds in the A to C bituminous range. More than a dozen of these beds are of sufficient thickness to warrant interest from the perspective of CBM.

While some seams can contain as much as 220 cubic ft of methane per ton, not all Kansas coal beds are potential candidates for CBM production; sufficient overburden and a competent shale seal are necessary too. CBM production centers on Wilson and Montgomery counties in southeastern Kansas from depths greater than 500 ft in fracture- stimulated wells. Some production also comes from western Labette and eastern Chautauqua counties. The number of CBM wells doubled in 1997, when compared to the 232 wells in 1993, and further growth is expected. The area has the advantage of pipeline networks already in place and ample recognized zones for disposing of produced waters.

Oklahoma’s first CBM production was established in 1988 from a Middle Pennsylvanian Hartshorne coal in the Arkoma Basin at depths of 600 to 700 ft. The first horizontal CBM completion took place here in 1998. More than 90% of the completions have been from Hartshorne coals, and most reservoirs are located on the flanks of anticlinal structures. Typical initial production from CBM wells is 72 mcf/ day, with 10 bwpd.

CBM production began in 1994 on Oklahoma’s Northeastern Shelf from high volatile bituminous coals of the same general age and character as those found in southeastern Kansas. Average completion depth was 918 ft, and 22 wells perforated more than one coal bed. Typical initial production was 29 mcf/ day and 66 bwpd. After 3- 12 months, production on average stabilized at more than 1 mmcf per month.

Enhanced coal bed methane (ECBM) recovery using CO ₂ injection has not been implemented yet in the Midcontinent area. However, there have been pilot studies in the San Juan Basin in New Mexico, where ECBM by CO ₂ injection is projected to add 5 to 10 tcf to the approximately 13 tcf already booked as reserves. The outlook for CO ₂ is promising for a number of US basins with CBM that have: (1) minimal faulting and reservoir compartmentalization, (2) laterally continuous and permeable coal seams, (3) a concentrated geometry of coal seams, and (4) ready availability of CO ₂ .

There are some some real advantages for ECBM by CO ₂ injection in deeper reservoirs where primary production falls quickly because coal cleat permeability drops rapidly with decreasing pressure. Maintaining the reservoir pressure should lead to appreciably better recoveries, especially at depths greater than 5,000 ft. A general rule of thumb predicts recovery for CO ₂ ECBM at about 25% above primary recovery. The potential for injection is encouraging, particularly in CBM wells drilled between 1979 and 1993 to capture more gas before the Section 29 Tax Credit expires at the end of 2002.

In theory, CO ₂ can displace 100% of the adsorbed methane from coal surfaces. Although nitrogen is also a candidate for ECBM, CO ₂ has some distinct advantages and usually costs less in many areas. Often it occurs naturally at moderate to high pressures, and, because miscibility is not an issue, additional compression is not necessary. Breakthrough of CO ₂ will usually take longer than nitrogen in an equivalent reservoir, which can displace more gas from the reservoir. Cryogenic or membrane technologies can be used to separate CO ₂ from the gas stream after breakthrough. An additional advantage is that sequestration credits may soon be available for subsurface disposal of excess CO ₂ from numerous surface operations.

The major disadvantage is that it takes about 2 mcf of injected CO ₂ to displace one mcf of methane, while only about one mcf of nitrogen is required to obtain the same amount.

LESSONS LEARNED

To ensure a technically and economically successful CBM venture, the operator must have either a large proprietary acreage block or have cooperative agreements with other operators addressing development of the CBM resource. The quality of the gas must be assessed, as should the proximity of pipelines and their operating pressures. Cultural and natural features of the area must be accounted for, as well as environmental laws and rules.

When drilling CBM wells, the following are good rules: (1) cluster wells to aid in dewatering the reservoir, (2) maximize the interior wells, (3) maintain a well spacing that will lead to well interference, (4) leave adequate rat hole below perforations so fluid levels can be kept below them, and (5) air drill to minimize formation damage.

Good rules to follow in well completion are: (1) minimize cement leak- off into coals, (2) produce a common coal in each well, and (3) frac wells to cause interference.

Suggested operations practices include: (1) drilling a disposal well at the outset, (2) selecting pumps as a function of needed sand protection, (3) testing produced water to anticipate potential future scaling problems, (4) planning for the eventuality of a low- pressure or vacuum system, and (5) centralizing any needed compression facilities.

CONNECTIONS:

Lawrence Brady, Senior Scientist, Geology
Kansas Geological Survey University of Kansas,
1930 Constant Ave. Lawrence, KS 66047- 3726
Phone 785- 864- 3965, Fax 785- 864- 5317 E- maillbrady@kgs.ukans.edu

Brian J. Cardott, Geologist
Oklahoma Geological Survey,
100 E. Boyd, Rm. N- 131
Norman, OK 73019- 0628
Phone 800- 330- 3996, Fax 405- 325- 7069, E- mail bcardott@ou.edu

Lanny G. Schoeling, Senior Reserve Engineer
Shell CO ₂ Company, Ltd.
200 NorthDairy Ashford,
Houston, TX 77079
Phone 281- 544- 4856, Fax 218- 544- 3841, E- mail lgschoeling@shellus.com

For information on PTTC’s North Midcontinent Region and its activities contact:
Rodney Reynolds, Project Manager, Energy Research Center, and Petroleum Engineer
Tertiary Oil Recovery Project, University of Kansas
1930 Constant Ave., Lawrence, KS 66047
Phone 785- 864- 7398, Fax 785- 864- 7399, E- mail reynolds@cpe.engr.ukans.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

Petroleum Technology Transfer Council, 2916 West T. C. Jester, Suite 103, Houston, TX 77018
Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org; web www.pttc.org