December 2011, Vol. 238 No. 12


EPA To Consider Shale Gas Wastewater Regulation

To no one’s surprise, the Environmental Protection Agency announced in October that it will think about regulating shale gas wastewater. The Department of Energy’s shale gas subcommittee – formed at the request of President Obama – provided the impetus to the EPA by noting the “fracking” chemicals contained in the water injected into shale rock formations and the contaminants that “flowback” to the surface both should be looked at more closely in case they are contaminating drinking water sources.

But the EPA isn’t going to be moving fast on potential wastewater “pre-treatment” standards it can impose under the Clean Water Act. The first thing it plans to do is conduct extensive data gathering, including site visits, stakeholder outreach, and development of a national survey of the industry. That process is likely to take years. The EPA is already trying to do a survey of hydraulic fracturing and drinking water, requested by Congress in 2010, which the agency has been trying to get off the ground for a year. Any results of that first study won’t be ready until the end of 2012, if then. And that is only a study.

The potential action under the Clean Water Act the EPA announced in late October has a more direct link to potential regulatory action. There are already effluent standards for the oil and gas industry which prohibit release of shale wastewater into oceans, rivers and streams. There are no “pre-treatment” standards pertaining either to the fracking chemicals or the wastewater disgorged from the well, which can total up to 1 million gallons from a single well within the first 30 days after fracturing.

Dan Whitten, vice president of Strategic Communications for America’s Natural Gas Alliance (ANGA), says, “Like all oversight of natural gas development, wastewater disposal is actively regulated at the state level. ANGA continues to believe that state regulatory professionals are best qualified to assess the unique geological characteristics of the shale plays in their region and the appropriate water disposal requirements that arise from those conditions. As EPA officials move forward we encourage them to partner with the states and take into serious consideration state regulators’ existing on-the-ground expertise and ongoing oversight activities.”

Wastewater associated with shale gas extraction can contain high levels of total dissolved solids (TDS), fracturing fluid additives, metals, and naturally occurring radioactive materials (NORM). The big concern in terms of wastewater is TDS which is found at levels typically about 100,000 ppm and can be as high as 400,000 ppm. Available data indicates the levels of TDS in shale gas wastewaters can often exceed recommended drinking water concentrations by a factor of 200.

In terms of current wastewater disposal practices, re-use of shale gas wastewater is, in part, dependent on the levels of pollutants in the wastewater and the proximity of other fracturing sites that might re-use the wastewater. Wastewater that is not recycled is trucked to a publicly owned treatment works (POTW) for treatment and disposal. POTWs are likely effective in treating only some of the pollutants in shale gas wastewater, such as the conventional and organic pollutants. These treatment technologies are not designed to treat high levels of TDS, NORM, or high levels of metals.

In the Barnett Shale area, wastewater is often injected into brine disposal wells.

Senate Committee Examines LNG Exports
Exports of LNG were the only issue on the menu at hearings in the Senate Energy Committee on Nov. 8. The Department of Energy has four applications from four U.S. companies to export LNG. But groups such as the American Public Gas Association and Industrial Energy Consumers of America oppose approval of those applications to export natural gas to countries with whom the U.S. does not have a Free Trade Agreement (FTA). The DOE cannot block LNG exports to countries with whom the U.S. does have an FTA.

The four companies with pending export applications are Lake Charles Exports, Freeport LNG, Dominion and Jordan Cove Energy Project. They want to export LNG to both countries with and without FTAs with the U.S. The DOE has leeway to block exports to non-FTA countries.

The DOE approved the first LNG export application last May. That was from Sabine Pass Liquefaction, which is now able to export 2.2 Bcf/d to both FTA and non-FTA countries.

The case for and against LNG exports are clear; but weighing them against each other is not easy. LNG exports create jobs and provide markets for domestic natural gas. But the exports could lead to higher natural gas prices in the U.S. That latter point is why the APGA and IECA are opposing the export applications.

At the hearings in the Energy Committee on Nov. 8, Chris Smith, deputy assistant secretary for oil and gas in the DOE office of fossil energy, said the Energy Information Administration was doing a study looking at the potential increase in natural gas prices in the U.S. which could occur if the four additional export licenses are granted. Smith did not say whether the DOE would wait for the results of those two studies before acting on the four pending export applications.

None of the members of the committee – neither Democrats nor Republicans – seemed to have much of an opinion one way or another about LNG exports, except for Sen. Lisa Murkowski (R-AK), the top Republican on the committee. She backed the continuation of LNG exports from Cook Island in Alaska, most of which goes to Japan.

Virginia Senator Wants State In New Offshore Drilling Plan
Insisting that the Interior Department was mistaken to leave Virginia off its latest proposal for offshore drilling, Sen. Mark Warner (D-VA) told Platts Energy Week added this would be contingent at he would on Virginia getting some of the royalties. Warner said he will ask Interior Secretary Ken Salazar to reconsider his decision last month excluding Virginia in the administration’s first five-year offshore leasing proposal.

Among the reasons given for excluding Virginia was that seismic data for the waters was too old and that the U.S. Navy, which bases its Second Fleet in Norfolk, had concerns about navigation in waters with oil and gas infrastructure.

“It’s the wrong decision, I hope they’ll reconsider, and remember, if we start this process it will be years before we see any oil or gas coming off the state of Virginia. Putting Virginia into this lease process is just the beginning of the process. The Navy will still have a chance to weigh in; we’ll still have a chance to obviously have the environmental concerns thoroughly vetted,” Warner said.

Virginia was included in the Bush administration’s plan for offshore development, an idea shared by President Obama until the April 2010 BP Macondo blowout in the Gulf of Mexico.
“We obviously needed to take a time-out after the Gulf disaster,” Warner said. “And we have to make sure there are going to be lessons learned from that disaster into any future drilling, whether it’s off the coast of Virginia or in the Gulf or anywhere else. I’m comfortable that by the time drilling is actually in place, all the lessons learned will be incorporated.”


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