The Department of Energy puts up some numbers that help define how potential water disposal regulations in the Powder River Basin could impact US gas supply.

As many as 39,000 coalbed methane wells are expected to be drilled in the Powder River Basin (PRB) of Wyoming and Montana over the next 10 years. In advance of this activity, the Bureau of Land Management (BLM) must prepare Environmental Impact Statements (EIS's) evaluating the environmental impacts associated with this development. Draft EIS documents for Wyoming and Montana were released for comment in early 2002 and final versions in January 2003. The U.S. Environmental Protection Agency (EPA Region 8) also is conducting a study of Best Professional Judgment (BPJ) general permit requirements for produced water on Native American lands in the region. The regulatory impact of these evaluations will significantly influence the development of coalbed methane resource in the Powder River Basin, particularly if they lead to the requirement of more expensive approaches to produced water disposal. Recognizing the potential impact of these decisions on the supply of natural gas in the U.S., the Department of Energy (DOE) undertook a comprehensive analysis to quantify the impact of alternative water management approaches on the volume of economically recoverable coal seam gas in the PRB.

The results of this effort, carried out by Advanced Resources International, a consulting firm in Arlington, Va., are revealing. They show that under the most likely set of economic and infrastructure assumptions, a blanket regulation requiring produced water to be "actively" treated (e.g., reverse osmosis) before discharge would result in a shift in status of between 12 and 15 Tcf of gas from economic to uneconomic (depending on the mode of RO residue disposal). This equates to a loss of roughly US $1.5 billion in Federal royalties alone, as well as about $2 billion in state tax losses.

There are several points the 213-page report makes clear: assessments of PRB gas-in-place vary depending on data and methodology, more recoverable gas does not necessarily mean more wells, and consideration of a mix of produced water management alternatives rather than a "one-size-fits-all" approach could significantly impact the volume of coalbed methane available to the nation.

The endpoints of the range of coalbed methane resource estimates for the Powder River Basin vary by a factor of almost five. This study estimates the PRB contains 61 Tcf of coalbed methane gas-in-place. Earlier estimates by the Potential Gas Committee (2000) and the U.S. Geological Survey (2002) put the total at 24 Tcf and 14 Tcf respectively. Such differences are not unexpected when different methodologies, models and assumptions are employed to calculate a quantity as nebulous as undiscovered recoverable gas. The reasons for the increase in this report are noted: more complete and extensive information on the deeper Fort Union coals, new data on the Wasatch coals on the western edge of the basin, the inclusion of coals in the Montana portion of the PRB, and the identification of free gas saturations and higher gas content values in particular coal intervals. The report's estimate of a maximum of 39 Tcf of technically recoverable gas (as compared to 24 Tcf and 14 Tcf by the PGC and USGS, respectively) is based on reservoir modeling using 142 "type wells" to represent the range of production performance seen across the basin. Interestingly, this detailed study concludes that higher gas content will allow development of this larger resource volume with fewer wells and less water production than has been projected in the past - about 4,000 fewer wells and 5 billion fewer barrels of produced water than estimated in the draft Wyoming EIS.

The report also looks at two other produced water disposal alternatives to the most expensive option of reverse osmosis treatment with surface discharge of the treated water and deep well disposal of the residual concentrate stream. These alternatives are: infiltration impoundment with enhanced evaporation or surface spreading; and shallow re-injection. Deep re-injection of all produced water was not considered, as it would constitute the loss of a valuable water resource and also would be much more expensive. The total volumes of recoverable gas that would become uneconomic should either of these two alternatives be required over surface discharge, are 2.4 Tcf and 3.6 Tcf, respectively. This loss of about 10% to 15% of the recoverable total is much less than the 50% to 70% loss of economically recoverable resource that would result from a requirement to employ RO for every barrel of water produced. While the option of shallow re-injection is dependent on the availability of suitable shallow zones, a significant unknown at this point, the analysis points out how important the choice of water disposal regulations can be in a basin where water drives the economics.

According to Rita A. Bajura, director of DOE's National Energy Technology Laboratory, "The results of this study were exhaustively peer-reviewed by representatives of the BLM, EPA and the USGS, as well as from multiple state agencies (Wyoming and Montana). Their comments were overwhelmingly positive. We hope they will find it to be useful in their continued efforts to promote environmentally sound development of the Powder River Basin's coalbed methane resource."

Efforts to advance the technology of gas production and water management practices, including analysis of the options for beneficial use of coalbed methane produced water and research on technologies for produced water treatment, can help to maintain the economic viability of Powder River Basin coalbed methane development. This will be critical if we are to avoid decisions that could take 12 to 15 Tcf of domestic gas supply off the table in the face of steep declines in domestic gas production and steep increases in domestic gas demand. Currently, lower-48 proven gas reserves amount to just more than 180 Tcf and we consume about 22 Tcf each year.

The complete report is available online at the National Energy Technology Laboratory's Strategic Center for Natural Gas Web site at www.netl.doe.gov/scng. The report is also available on CD.


Comments