Table of Contents

Vol. 6, No. 2
2nd Quarter 2000

New Opportunities in Coalbed Methane
For Independent Producers
by Karl Lang, Hart/IRI Fuels Information Services

Over the last ten years, coalbed methane (CBM) has gone from being a coal mine nuisance to a high-cost scientific curiosity to a “one-play wonder” to a low-cost, low-risk source of long-term reserves. Following on the success of the San Juan and Black Warrior Basin plays, the Powder River Basin is currently one of the most active natural gas plays in the country and a growing number of companies are developing CBM in a number of other emerging basins.

In 1998, CBM supplied 6 percent (1.2 Tcf) of total US dry natural gas production. More than 8 Tcf has been produced over the past decade, and there are now more than 8,500 CBM wells. According to GRI (formerly the Gas Research Institute), there is a large, abundant CBM resource base in the US lower-48: proved reserves of 12.2 Tcf, another 20 to 50 Tcf that is economically recoverable, and between 87 and 110 Tcf that is undiscovered. There are also huge coal deposits in Alaska that contain an estimated 1,000 Tcf of methane resource. Although most of the gas produced to date has come from the San Juan Basin, new basins are emerging and beginning to make significant contributions. (See Figure 1)

Operators have discovered, however, that rules-of-thumb determined in the San Juan and Warrior basins are not universal. It appears the continued success of CBM in US basins will depend on two factors: (1) operators’ abilities to tailor technologies to each basin’s unique characteristics in ways that keep costs down, and (2) a regulatory environment that does not hinder the application of new or existing technologies. A third factor that may eventually effect the economics of CBM involves the interplay of both technology and government regulation: carbon sequestration through CO2 injection.

According to Mike Zuber, an engineer with Schlumberger-Holditch Reservoir Technologies, “The one thing coalbed methane plays in the US have in common is that they are all different. You have to consider the complete package of coal characteristics, regional geology, and infrastructure…you can’t get locked into one mindset.”

Schlumberger-Holdtich has compared CBM production trends across the different basins and learned that each play is economically successful for different reasons. In many cases, independent producers have been able to make money in basins that didn’t look profitable at first, by using innovative technologies and keeping costs low.

Over the last year, PTTC held a series of six workshops on CBM topics at sites across the country. These workshops highlighted a number of trends that are revisited below.

Powder River Basin

Although very thick, the low gas content, low pressure, high permeability coals of the Powder River were not at first thought to be good candidates for CBM development. Initial wells drilled and completed following the San Juan model were not promising; conventional cement jobs plugged the natural fractures and tests of the thicker, deeper coal seams produced large volumes of water without much gas. Only when companies began to drill low cost (current well costs are as low as $35,000 and take 2 to 3 days to drill and complete) shallow wells at the basin margin and complete the wells open hole, did the real potential of the play become apparent. Added to the low drilling costs is the fact that produced water in the Powder River basin is fresh enough to be discharged to the surface.

More than 40 companies are in the play at this point, one of the most active being Pennaco Energy, which drilled 550 gross wells in 1999 and plans to drill another 800 during 2000. Alone or together with major partner CMS Oil and Gas, Pennaco holds 350,000 net acres, and expects to continue to develop reserves for at least the next ten years. A joint venture of Western Gas Resources and Barrett Resources, Lance Oil and Gas, has an even larger presence with 926,000 gross acres. Lance drilled 580 wells in 1999 and plans to drill about 800 during 2000. Between them, Pennaco and Lance produce nearly 200 MMscfd, the majority of the coalbed gas being produced in the basin.

In spite of these large acreage positions, there is room for innovative operators. Preston, Reynolds & Co., Inc., recently acquired by Williston Basin Interstate, has developed three projects in Wyoming and Montana and currently has about 350 wells producing. They constantly experiment with drilling and completion designs, as well as with the design of gathering systems.

The company’s vice president of engineering, Roland DeBruyn, describes the operations: “In the Powder it is important to match technology to geologic reality and not discount unconventional ways of dealing with an unconventional resource. The task is to complete shallow wells, pump a lot of water and move low pressure gas, at low cost. We designed an electronic system to control the downhole electric pumps on our wells, allowing us to monitor them on a real-time basis and lengthen the service lives of what are actually inexpensive, light-duty pumps. We worked with a supplier to create a low maintenance rotary-screw compressor package for low-pressure gas gathering that can be quickly sited and re-sited. We’re looking at horizontal wells this year, trying to reduce the number of wells we need, despite the fact that a 500-600 ft TVD makes for a radius that is difficult to navigate with a pump. As we advance our technology, our well performance is getting much better.”

Raton Basin

Activity in the Raton Basin has picked up since the completion of a CIG pipeline in 1994 and a lateral in 1998. Evergreen Resources is the largest active developer with approximately 200,000 gross acres. In addition, Evergreen’s daily gas sales represent more than 75% of the gas currently sold from the Raton Basin. According to Evergreen, the company has drilled more than 200 producing gas wells on its Raton Basin properties, and has identified about 800 additional locations.

The Raton contains two coal bearing formations. To date, Evergreen’s gas production has been from the Vermejo formation coals (between 450 and 3,500 feet); however, the company believes that the shallower Raton formation coal seams may be profitably exploited as well. Devon Energy and El Paso Energy Corp., after acquiring PennzEnergy and Sonat Exploration, have maintained interest in jointly developing CBM reserves in the Vermejo Ranch property in the New Mexico portion of the basin. Devon has drilled 80 wells so far this year and early indications are very positive.

Uinta Basin

The leading producing field in the Uinta Basin, Drunkards Wash, is operated by River Gas Corporation, a CBM producer with experience in western Alabama. The field has more than 200 producing wells and the plan is for a total of 600. Faced with operating a 200 square mile field on a remote plateau in eastern Utah, River Gas chose to reduce overall costs by installing an automated system that permits them to operate the wells with a minimal staff from a remote station.

The system includes a radio system for communicating well data and remote control commands, electronic gas measurement to eliminate chart recorders, and a supervisory control and data acquisition (SCADA) system to manage the operation. The system is effectively operating 275 wells, 8 disposal wellsites, 5 gas metering stations and 2 reservoir monitoring wells. This investment in technology to reduce overall operating costs, is another example of how producers are tailoring technical solutions to individual CBM basins.

Other Basins

Relatively limited commercial exploitation of CBM has taken place in other basins, but that is changing. Production has been established in the Piceance (about 7.8 Bcf/year), Greater Green River, Cherokee, Arkoma, and Illinois Basins. While the Appalachian basin has seen some CBM production in Pennsylvania (30 wells) and West Virginia (36 wells), the bulk of the production is from southwestern Virginia. In 1998, 1321 Virginia wells produced a total of 42.6 Bcf.

Alaska contains nearly half of the total US coal reserves. Studies done by the State of Alaska have shown that coals in Northern Alaska’s Colville Basin, the Yukon Basin and the Chignik Basin of the Alaskan Peninsula have the highest CBM production potential. Work is currently underway to drill and test wells in the Colville Basin, near the villages of Wainwright and Atqasuk. In the Matanuska Valley near Cook Inlet, Unocal has begun the first phase of a multi-well pilot project near Wasilla. Alaskan CBM will most likely be for local consumption.

Environmental Issues

Because CBM development requires the production of significant volumes of water, the disposal of produced water is an important factor in the economics of any project. In some cases, the water produced from coal seams is fresh enough to be put to beneficial uses.

In the Powder River basin, for example, ranchers are stocking disposal ponds with fish. There are some concerns that too much potable water is being pumped from the aquifer system. In other areas like the San Juan, Warrior, and Appalachian basins, salinity is more variable, but conventional approaches have generally worked and water disposal has not become a major issue. Unexpectedly, a significant environmental issue has developed not from water being produced from coalbed wells but from pumping water into them.

In Alabama’s Warrior Basin, a court case begun in 1989 has led to a situation where CBM wells are now subject to underground water injection regulations by virtue of their having fracturing fluids injected into them during completion operations. This means that fracturing fluids must now be certified as meeting primary drinking water standards, complicating what was once a straightforward well permitting process.

While the US Environmental Protection Agency (EPA) has approved the Alabama State Oil & Gas Board’s new program for regulating CBM wells, the claimant in the original case has filed a petition opposing that approval. According to Dennis Lathem, executive director of the Coalbed Methane Association of Alabama, “If this approach spreads to other basins, the impact could be felt not only in the coalbed methane industry but by any company doing hydraulic fracturing anywhere in the nation.”

Throughout the legal process in Alabama, no evidence of any actual groundwater contamination from CBM well fracturing was found. A 1998 survey done by the Ground Water Protection Council determined that in the 13 states with CBM activity, there was not a single confirmed case of groundwater contamination as a result of hydraulic fracturing. Although none of the substances added to fracture stimulation makeup water in Alabama is considered a contaminant by the EPA, the water itself must meet the standard, and most streams, rivers and lakes in Alabama are not potable. The result is that operators must buy and transport water from public water systems in order to formulate a fracturing fluid that is more drinkable than natural surface water at the well location.

CO₂ Sequestration

In the future, CBM resources may be influenced by a serendipitous combination of two otherwise unrelated facts: (1) adsorption of CO₂ by coal enhances the desorption (and consequent production) of methane, and (2) governments are moving toward assigning value to the prevention of CO₂ released into the atmosphere.

Injecting CO₂ into coal seams enhances the release of methane from the coal while permanently removing the CO₂ from the environment. However, the economics of permanently “sequestering” CO₂ in coal seams depends on three factors: the value of any credits that might be offered by governments for capturing it, the cost of collecting the CO₂, and the incremental recovery obtainable from CO₂ injection.

If a market is created where transferrable “CO₂ credits” can be acquired and sold, if the cost of removing and concentrating CO₂ from power plant flue gas can be lowered, and if significant incremental recovery is possible, an economic case could be made for injecting CO₂ into existing CBM projects or into seams that might not otherwise be profitable methane producers. This could have the beneficial effect of increasing the available volume of clean-burning natural gas while simultaneously reducing the volume of CO₂ in the atmosphere.

Conclusion

In the meantime, the general trend in CBM appears to be similar to the path followed by most independent producers every day: keep it simple, find ways to operate as inexpensively as possible, and don’t be afraid to make investments when technology can lead to better returns. There is a large amount of public information and CBM case histories available, so the raw material is there for producers who are looking to find these better returns.

Note: The complete version of this article, with a table, can be accessed at www.pttc.org in the Communications Section.

RMAG Coalbed Methane Symposium Returns to Denver in June

The 2000 RMAG Coalbed Methane Symposium, co-hosted by Rocky Mountain Association of Geologists (RMAG), PTTC and GRI, is back for the second year. It will be held on June 20-21 in Denver.

This year’s Symposium, located at the Denver Marriott City Center, has been expanded to include topics covering all aspects of North American coalbed methane exploration, development and production. There will also be functions addressing environmental/ regulatory considerations, as well as summaries of activity and research in US and Canadian basins.

A detailed schedule and registration form can be found on the RMAG website: www.rmag.org or on the Rocky Mountain PTTC website: www.mines.edu/research/PTTC/

For more information, contact RMAG: phone 303-573-8621, email RMAGdenver@aol.com.

Author: Karl Lang is Director of Custom Publishing at Hart/IRI Fuels Information Services. He edits GasTIPS, a technical journal produced by Hart for GRI. He also writes for a number of Hart energy publications. E-mail: klang@phillips.com