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07 17, 2012 by Oil & Gas Journal
Excessive and poorly conceived federal regulations threaten to stifle an onshore US oil and gas renaissance that is being made possible by hydraulic fracturing and other new technologies, state officials and producers told the US House Oversight and Government Reform Committee. States are better qualified and have worked with producers and other stakeholders to develop rules that are effective and economic, they said at field hearings July 13 in Edmond, Okla., and July 14 in Fargo, ND.
State regulators have repeatedly shown that they can move faster than a federal bureaucracy, noted Patrice Douglas, an Oklahoma Corporate Commission member, during the July 13 hearing.
Douglas noted that in the 2 years that the US Environmental Protection Agency spent studying hydraulic fracturing, the State Review of Oil and Natural Gas Environmental Regulations Inc. (Stronger)—comprised of state regulators, environmental groups, and oil and gas producers—completed reviews of five states’ fracing regulations and made recommendations that states, including Oklahoma, have implemented.
“This is not meant to suggest that Oklahoma and other states are perfect. We are not,” Douglas added. “We have worked, and will continue to work, in a positive way with EPA and other federal agencies on matters of mutual interest in which we can share our collective expertise. We seek ways to improve.”
While the federal permitting process may make sense where large blocks of land are managed for federal ownership or trust responsibilities, federal mineral tracts in North Dakota outside Fort Berthold and the Dakota Prairie Grasslands are small parcels that resulted from right of way acquisitions and bankruptcies, according to Lynn D. Helms, director of the state’s Department of Mineral Resources.
Burdens and delays
In nearly every case, the surface estate has been sold, resulting in a split estate situation where the processes required to obtain a federal permit impose regulatory burdens and development delays on private property owners, he indicated during the committee’s July 14 hearing in Fargo.
“North Dakota has worked hard to create a stable tax and regulatory environment that promotes venture capital investment,” Helms said in his written statement. “Our oil and gas rules are reviewed at least every 2 years through a public comment process where every comment must be considered in writing. This ensures that North Dakota regulations keep up with new technologies and economic conditions.”
He said North Dakota’s Industrial Commission believes states that have adopted fracing rules that include chemical disclosure, well construction, and wellbore pressure testing should be exempt from proposed US Bureau of Land Management rules and EPA guidance. “The EPA guidance is written for enhanced oil recovery wells or disposal wells completed with tubing and packer,” Helms told the committee. “Most of the requirements will not work mechanically on wells completed with swell packers and fractured down the production casing as is common in North Dakota.”
Henry A. True, vice-president of Bridger Pipeline LLC and Belle Fourche Pipeline Co., said Bakken shale production growth has increased North Dakota’s crude oil production in 10 years to more than 640,000 b/d from 84,000 b/d. “North Dakota is now second to Texas in daily oil production,” he said in his written testimony. “However, when you compare infrastructure, Texas has over 50,000 miles of liquids pipelines, while North Dakota has less than 4,000 miles. Our estimates show that North Dakota production could reach 1.2 million b/d in the next decade, but there is a clear and significant infrastructure gap that needs to be solved.”
Jack R. Ekstrom, vice-president of corporate and government relations at Whiting Petroleum Corp. in Denver, said at the July 14 hearing that it was fortunate that much of the Bakken shale formation is in North Dakota, where individuals hold most of the surface and mineral rights and the state and federal governments have minor ownership. “Many in government are not aware that a federal drilling permit is required even when the federal government owns none of the surface and a minute fractional interest in the subsurface minerals,” he said in his written testimony.
Avoiding federal lands
Ekstrom added that the specter of more federal regulations, coupled with the US Department of the Interior’s “disingenuous and deceptive statements over many months related to so-called ‘unused’ leases” have led Whiting and many other producers to make federal acreage their last development choice. “Our strategy is to lease private lands and state lands, while avoiding federal lands and related costs and delays if at all possible,” he said.
“This industry, along with the associated jobs and energy from the fossil fuel it produces, is critical not just to Oklahoma but to the nation,” said Brian Woodard, vice-president of regulatory affairs at the Oklahoma Independent Petroleum Association, at the July 13 hearing.
“However, as I sit before you today and tout America’s current oil and gas renaissance, and as the blueprint has been laid for a true era of US energy independence, the current administration has countered with an equivalent flood of regulatory policies which threaten to undermine this bright energy future,” he continued in his written testimony.
He said instead of generating estimates from reports that producers submit already, EPA has imposed greenhouse gas reporting requirements on larger upstream independents that cost millions of dollars and make many companies integrate production software and new monitoring equipment into their daily operating systems.
EPA’s proposed new source performance standard for producers inappropriately uses methane as a surrogate for volatile organic compounds, Woodard continued. “In order to be cost effective, the rule should only apply to production streams which contain a meaningful VOC concentration,” he said. “For sources with significantly low to zero VOC content, such as dry gas shales like the Barnett, Haynesville, and others, the cost per ton of emission reductions drastically exceeds historically acceptable levels.”
EPA also developed an emission factor for well completions by improperly using Natural Gas STAR data, added Joe Leonard, Devon Energy Corp.’s environmental, health, and safety engineer. “In short, EPA assumes that gas recovered would have otherwise been flared or vented,” he told the committee at the July 13 hearing. “However, industry data shows that reduced emission completions account for significantly more gas produced and sold than would be flared or vented during older and less common completion processes.”
He noted that a recent study of more than 90,000 wells that the American Petroleum Institute and America’s Natural Gas Alliance jointly commissioned demonstrated that EPA’s estimates were at least 100% too high across upstream processes, a conclusion which followed similar industry work showing even greater errors.
“This is outrageous because EPA, using incorrect assumptions, applying inappropriate data, and then analyzing it improperly, has not only changed its emission estimates for completion operations on a forward-looking basis, but revised all oil and gas completion estimates back to 1990—a period before the combined use of horizontal drilling and hydraulic fracturing,” Leonard said in his written testimony.
Fossil fuel opponents also have tactically used the Endangered Species Act to slow down energy resource development, noted Mike McDonald, president of Triad Energy Inc. in Oklahoma City. He said that typically, they overwhelm the US Fish and Wildlife Service with hundreds of proposed candidate listings so the DOI agency can’t respond before mandated deadlines, then sue FWS which settles actions without examining the scientific evidence.
“Of the 1,391 animal and plant species listed, only 20 have ever been removed from the list,” McDonald said in his written testimony. “Several listed and candidate species, in particular the listed American Burying Beetle and the Lesser Prairie Chicken, affect drilling operations in Oklahoma. To protect the beetle, producers must hire consultants, who must put out survey traps containing carrion, file additional paperwork with FWS, and slow drilling operations during the beetles’ active period.”
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