Raton Basin

Uinta Basin

Other Basins

Environmental Issues

CO ₂ Sequestration

Sidebar - Coal and Methane

References

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 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 (1.20 Tcf) of total U.S. 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 (Hill, et al., 2000). According to GRI, there is a large, abundant CBM resource base in the U.S. 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 (Smith, 1995). 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 (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 U.S. 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 U.S. 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 coalbed methane 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. The results of this analysis will be one of the papers presented at the upcoming Coalbed Methane Symposium to be sponsored by the Rocky Mountain Association of Geologists, GRI, and the PTTC in Denver on June 20th and 21st.

Over the last year, the PTTC held a series of six workshops on CBM at sites across the country. These workshops highlighted a number of trends that are revisited below, several of which will also be the focus of work presented at the Symposium.

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 (Toal, 2000). 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. Pennaco drilled 550 gross wells in 1999 and plans to drill another 800 during 2000 (Toal, 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 (Toal, 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. According to Roland DeBruyn, VP of Engineering, “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 hundred 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 (Robertson, et al., 2000). 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 (Hill, 2000). 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 (Milici, 1999).

Alaska contains nearly half of the total U.S. 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 (Tyler, et al., 2000). 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 coalbed methane 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 coalbed methane 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 relatively straightforward well permitting process. While the Environmental Protection Agency (EPA) has approved the Alabama State Oil & Gas Board’s new program for regulating coalbed methane 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 coalbed methane well fracturing was found. A 1998 survey done by the Ground Water Protection Council (GWPC) determined that in the 13 states with coalbed methane 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, development of coalbed methane resources may be influenced by a serendipitous combination of two otherwise unrelated facts: (1) adsorption of CO₂ molecules by coal enhances the desorption (and consequent production) of methane, and (2) governments are moving toward assigning value to the prevention of the release of CO₂ into the atmosphere. Research has shown that 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” captured CO₂ in coal seams depends on three factors: the value of any credits that might be offered by governments for capturing the CO₂, the cost of collecting the CO₂, and the incremental recovery obtainable from CO₂ injection. If a market is eventually created where transferrable “CO₂ credits” can be acquired and sold by companies that capture CO₂ and inject it into coal seams, 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.

The Alberta Research Council (ARC), among others, has been looking at the economics of this approach. The Canadian government has gone on record promising to reduce CO₂ emissions and western Canada has a large coal resource that could be used as a “sink” for CO₂ collected from power plant exhaust. ARC simulated the performance of a 100 well, 320 acre-spacing five-spot coalbed methane project where the injection of a 95% CO₂ stream results in the recovery of 72% of the gas-in-place (as compared to about 44% without CO₂ injection). Assuming typical drilling, completion, stimulation and maintenance costs, and a delivered CO₂ cost of 1 US$/Mscf, the supply price of the methane is 2.89 US$/Mscf at a 12 percent real rate of return (Wong, et al., 2000), without any allowance for CO₂ credits. ARC is presently looking more carefully at the assumptions in this simulation to better understand the balance between CO₂ sequestration and methane production economics. After accounting for the CO₂ generated by the process, ARC calculates a 12% ROR can be maintained with a CO₂ credit of $15/ton at a $2/Mscf gas price and a $30/ton credit at $1/Mscf.

Theoretically, the incremental improvement in methane recovery due to CO₂ injection in coal seams can be significant, but there is not a lot of field data to support the theory. The only company to do this in a major way, Burlington Resources, has been injecting CO₂ into a Cretaceous Fruitland coal seam at its Allison Unit pilot in the Northern San Juan Basin since 1996 (Wong, et al., 2000). In this area, pure CO₂ is available from a number of natural sources for the relatively low price of about $0.65/Mscf. Unfortunately, the precise incremental production attributable to that project is clouded by other operations carried out over the same time period.

The other important factor is the cost of gathering CO₂. While some processes that vent relatively pure CO₂ would provide good sources (e.g., gas processing plants, synthesis gas plants, hydrogen manufacturing plants), the real target is combustion flue gas from power plants. Unfortunately, the CO₂ concentration in flue gas ranges is only 13 percent for a coal-fired plant and less for a gas-fired plant. The cost of separating the CO₂ is expensive, as much as 2.89 $/Mscf to separate, dry and compress 1000 tons/day from gas turbine exhaust (Wong, et al., 2000). New amine solvent technologies might be able to lower this to between 0.33 and 1.33 $/Mscf. Other new approaches may also improve efficiency, either by reducing the cost or by increasing the concentration of CO₂ in the exhaust.

The ARC is currently leading a 20-member consortium of international government and industry partners in a pilot test to gather field data to improve the industry’s understanding of CBM production enhancement. The first two phases of the work, proof-of-concept and a single-well micro-pilot test, were completed in 1999, according to Sam Wong, a research engineer with ARC. “Earlier this year we began two new pilots, one injecting a 50/50 mixture of CO₂ and N2, and one with a 13/87 flue gas mixture. We now have about a month’s worth of production data and we will be analyzing the results soon. One of our goals is to calibrate existing coalbed models to more accurately predict the effects of injecting CO₂/N2 mixtures.” An additional 5-spot injection pilot will be undertaken when the results of the current work are evaluated. The Consortium is also cooperating with several U.S. National Laboratories, Chevron, Texaco, Pan Canadian Resources, Shell CO₂ Co., BP-Amoco, and Statoil, in a 3-year study of geologic sequestration of carbon dioxide in a number of geologic formations, including coalbeds.

Nitrogen is also an option for enhancing coalbed methane production. While CO₂ adsorption drives the methane molecules off of the coal surface, replacing them with CO₂ (at a ratio of about two CO₂ molecules per methane molecule), inert nitrogen reduces the effective partial pressure of methane in the coal. A pilot N2 injection project operated by Amoco in the Fruitland Coal of the San Juan Basin between 1992 and 1994 increased the methane production rate from about 200 Mscfd to over 1MMscfd (Wong, et al., 2000). BP-Amoco has followed up this pilot with a larger, 12-injector, 34-producer nitrogen injection project that began at the Tiffany Unit in the northern San Juan Basin in early 1998.

The whole issue of greenhouse gas (GHG) credits is another factor in the equation. The Credit for Voluntary Reductions Act of 1999 (S.547), introduced in March 1999, and the Credit for Voluntary Actions Act (HR.2520) introduced in July 1999, permit companies to save credits and use them to meet future emissions limits or sell them under a future emissions trading system. While the legislation was endorsed by a number of industry groups, industry is not unanimous in its support. The debate on these bills has evolved into a debate over the need for and possible focus of additional research into climate change and ways to reduce greenhouse gas emissions.

All in all, the economics of enhanced coalbed methane production will depend on how the following questions are answered. What sort of incremental recovery can be attributed to CO₂ or CO₂/N₂ injection in field applications? Can the cost of collecting CO₂ from combustion gases be reduced? Will some sort of reliable GHG credit system be implemented?

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, 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.

Sidebar - Coal and Methane

Coalbed methane (CBM) is natural gas found in coal beds. In the 1980s commercial CBM fields were developed in the high “rank” (harder bituminous) coals of Alabama, and the San Juan Basin of Colorado and New Mexico. Higher rank coals contain gas that is generated by the action of heat and pressure on the organic material in the coal. Gas in low rank coals is created by the decomposition of organic matter by bacteria (biogenic gas). CBM is stored as free gas in the fractures (cleats), dissolved in the water in the fracture system, and adsorbed within the in the molecular structure of the coal. Up to 90% of the gas in place is adsorbed within the coal matrix. When water is produced from the fracture system, the pressure within the coal bed is lowered and gas held in the matrix begins to desorb and migrate to the evacuated fracture system. The goal of most CBM projects is to quickly dewater the coal and accelerate the desorption process. Typically, after an initial period of primarily water production, gas production begins to climb and water production decreases. Some wells do not produce any water and begin producing gas immediately, depending on the nature of the fracture system. The properties of CBM reservoirs in historically productive areas are shown in Table 1.

Table 1: Coalbed Methane Play Characteristics (Nelson, 1999)

Basin	State(s)	Producing Wells (1996)	Cum. CBM Production (1981-1996)	Typical: Net Coal Thickness (ft)	Typical Gas Content (scf/ton)	Typical Spacing (acres)	Avg. Prod. (Mcfd/well)	Est. Finding Cost ($/Mcf)
San Juan	CO, NM	3,036	3,857	70	430	320	2,000	0.11
Black Warrior	AL, MS	2,739	728	25	350	80	100	0.25
Central Appalachian	WV, VA, KY, TN	814	121	16	na	80	120	na
Piceance	CO	123	36	80	768	40	140	1.23
Powder River	WY, MT	193	17	75	30	80	250	0.25
Uinta	UT	72	14	24	400	160	690	0.25
Raton	CO, NM	59	8	35	300	160	300	0.18

References
Hill, D.G. et al.; 2000. “Changing Perceptions Regarding the Size and Production Potential of North America Coalbed Methane Resources,” Presentation given at the SRI Coalbed and Coal Mine Methane Conference, Denver, March 27-28.

Milici, R.; 1999. “Coalbed Methane Assessment in the Central and Northern Parts of the Appalachian Basin,” PTTC Workshop on CBM in the Eastern United States, Lexington, KY, September 16.

Nelson, Charles; 1999. “Changing Perceptions Regarding the Size and Production Potential of Coalbed Methane Resources,” GasTIPS, GRI, Vol. 5, No. 2.

Robertson, S.K. et al.; 2000. “Automation System Case Study of Coalbed-Methane Development,” SPE 59789, SPE/CERI Gas Technology Symposium, Calgary, April 3-5.Toal, Brian; 2000. “A New Power In The Powder,” Oil and Gas Investor, March.

Smith, T. N.;1995. “Coalbed Methane Potential for Alaska and Drilling Results for the Upper Cook Inlet Basin,” paper presented at the University of Alabama, INTERGAS’95, Tuscaloosa, May 15-19.

Wong, S. et al.; 2000. “Economics of CO₂ Sequestration in Coalbed Methane Reservoirs,” SPE 59785, SPE/CERI Gas Technology Symposium, Calgary, April 3-5.

Author: Karl Lang is Director of Custom Publishing at Hart Energy Publications, a part of Phillips Business Information, Inc. He edits GasTIPS, a technical journal produced by Hart for Gas Research Institute (GRI). He also writes for a number of Hart energy publications. E-mail: klang@phillips.com