Hydraulic fracturing is a game-changing technology that has set off a regulatory scramble among the states and federal government even as it generates a bonanza of natural gas, natural gas liquids, and crude oil production throughout the U.S.
The hydraulic fracturing process, also known as fracking, requires that large quantities of water mixed with sand and surfactants are injected under high pressure into wells, breaking up dense shale thousands of feet below, releasing trapped gas and oil. The water that flows back to the surface can be reused, but eventually must be treated and the impurities disposed.
Hydraulic fracturing has been used in the U.S. since the late 1940s, but the technology has advanced to where it is now being applied at greater depths and pressures to rock layers that are the source of the oil and gas instead of simply opening trapped pockets of hydrocarbons. The rapid expansion of drilling in recent years has drawn the attention of regulators and politicians.
Major fracking operations got underway in earnest in the Barnett Shale in the Fort Worth Basin in Texas in 2003 and in the Marcellus Shale formation in Pennsylvania by around 2007. Large-scale oil and gas drilling activity is familiar in Texas; in Pennsylvania, however, even with its long history of oil and gas development, the exploration and production boom that burst open in 2007 caught many people unaware, resulting in a certain level of public controversy and scrutiny from state officials.
“Pennsylvania is the poster child for a surprise hit in oil and gas development,” said Jim Gooding, Ph.D., geoscientist and industry specialist in Black & Veatch’s Management Consulting Division.
Cost of new regulations
Fracking operations are pervasive in Texas and are underway in Louisiana, North Dakota, Ohio, Wyoming, and other energy-producing states. The resulting boom has brought gas prices down to the lowest levels in years. A trend in increased oil production through fracking has also contributed to reduced oil imports. These trends, in turn, have created an entirely new market dynamic affecting pipeline flows, utilities’ fuel use, and the economics of drilling for gas rich in natural gas liquids. What will be the impact of new regulations on supply and pricing?
“We see fracking regulation costs ranging between 20 cents and $1.15 per million Btu (mmBtu),” said Mike Donnelly, Ph.D., chief geoscientist and director of Natural Gas and Power Fuels in Black & Veatch’s Management Consulting Division.
That estimate is generally consistent with the answers from 80 percent of the respondents queried for Black & Veatch’s “Strategic Directions in the U.S. Natural Gas Industry” report — who stated they thought fracking costs would be $1/mmBtu or less. Donnelly said that technology advances will also help keep these costs in line.
“While consumers and the energy industry in general will prefer costs to be at the lower end of the range, based on these estimates, we think the market can accommodate reasonable fracking regulations,” Donnelly said. “Looking at the numbers, we think gas prices at up to $7 will have a clear market advantage among power generation fuels. Therefore, if 2020 gas prices approach $5.50/mmBtu, as we forecast, fracking regulation costs would not appear to make gas uncompetitive in the market.”
In response to the high level of shale development that quickly spread to other traditional oil and gas basins, as well as areas that previously had seen little activity, states began taking the lead in updating their oil and gas regulations. While the federal government is the main driver of most environmental regulations, the Energy Policy Act of 2005 all but sidelined the Environmental Protection Agency when an exemption for hydraulic fracturing was carved out of the Safe Drinking Water Act.
“The EPA has limited authority for regulating hydraulic fracturing,” said Andy Byers, associate vice president of Energy Environmental Services for Black & Veatch. “States have primary authority over these operations, and as a result, are more proactive in setting the standards.”
The Energy Policy Act exempted drillers conducting hydraulic fracturing from having to get an underground injection control permit, Byers said. The EPA’s authority was limited to regulating drilling operations that used diesel fuels in the fracking cocktail. “Since then, the industry took off, and EPA has been scrambling to assert its jurisdiction over fracking activities,” Byers said.
Gooding explained that 60 years ago, hydraulic fracturing commonly involved diesel oil, kerosene, and other petroleum derivatives as the working fluid. In addition to being environmentally worrisome, the petroleum distillates are not as effective as water-based fluids in achieving the desired results.
“No one has used ‘diesel’ as the working fluid of choice for a very long time, but EPA in the last year or two sought to broaden the definition to include many of the organically based additives that are used in modern fracking fluid formulations,” Gooding said. “That move was seen by the industry as EPA’s aggressive intent to find a grapple point for the regulation of hydraulic fracturing.”
With the change of EPA administrators in 2013, the “redefine diesel” campaign has cooled down, but it has not gone away, Gooding said. EPA is considering reinterpreting its existing enforcement authority as a means to establish new national rules on hydraulic fracturing, he noted.
Under the Safe Drinking Water Act, the states can assume enforcement responsibility in regulating injection wells for waste disposal, which can include wastes from hydraulic fracturing. EPA can also take this oversight back if they determine a state’s program is not sufficient, Gooding explained. “A couple of dozen states are rushing forward to strengthen their regulations with the clear intent of retaining their primary jurisdiction,” he said.
Many of the states had not updated their oil and gas regulations since the 1970s or 80s. “Then shale gas came along, and a lot of states found that their regulations were obsolete, particularly relative to fracking, horizontal drilling, and wastewater disposal. They are rushing to get updated before EPA tries to pull back their authority,” Gooding said.
State versus federal regulations
The interaction between the states and the EPA can be adversarial at times, noted Kevin Sunday, then deputy press secretary for the Pennsylvania Department of Environmental Protection (DEP). “The first oil well drilled in the U.S. was in Titusville, Pa., in 1859, so we have a long history of drilling and are successful at regulating it,” he said.
Sunday said that Pennsylvania’s 1984 oil and gas legislation laid down a lot of the groundwork on managing the impact of drilling on private water supplies. The Oil and Gas Act of 2012 stiffened the civil penalties for violations, increased the setbacks from buildings and private wells, and required well operators to report the content of fracking fluid to the state, as well as putting the information online. The law also strengthened the regulations regarding cementing and casing that were already in place and required regular pressure testing and quarterly testing of casing integrity.
Officials from Canada, Poland, the former Soviet Union, and other Eastern European countries have sought advice from the Pennsylvania DEP on crafting fracking regulations.
Also in Pennsylvania, the Susquehanna River Basin Commission (SRBC), which has been highly proactive in setting regulations dealing with water withdrawals in the basin for fracking operations, set a rulemaking in motion early in 2013 affecting withdrawals on headwaters regions or small watersheds.
The Susquehanna Basin watershed covers approximately half of Pennsylvania, along with parts of New York and Maryland, and there are certain areas where the streams are very small. “Our concern is not the overall water quantity use by the industry, but where are they getting it from and at what time of the year,” said Susan Obleski, who at the time was the press officer for the commission. “The new rules are part of a natural progression.”
States reevaluate regulations
Starting about two years ago, Arkansas, Louisiana, Oklahoma, Texas, West Virginia, and Wyoming made post-shale updates to their oil and gas regulations. New Mexico, Colorado, California, Tennessee, and Maryland began the process, Gooding said.
“There is another play called the Utica Shale,” he said, “which is chock full of natural gas liquids, and everyone is eager to get at it. Most of the good stuff in the Utica lies under Ohio, and Ohio is aggressively working to update their oil and gas regulations.”
A spokesman for Energy in Depth, a research, education, and public outreach campaign launched by the Independent Petroleum Association of America, said that a state’s regulatory development depends on its oil and gas experience. North Carolina, for example, doesn’t have a history of oil and gas development to speak of, and as a result, hasn’t had any comprehensive regulations, he said.
So when the state, with the help of the U.S. Geological Survey, discovered shale resources, it started looking at this for the first time. On June 4, 2014, North Carolina Governor Pat McCrory signed legislation lifting a moratorium on hydraulic fracturing, which could begin in 2015. At other end of spectrum, states like Texas and Wyoming, with their long history of hosting oil and gas operations, have passed or are considering regulatory changes that would require disclosure of fluids in the fracking process, he said. Most recently, the New York State Court of Appeals on June 30 ruled that towns can enact bans on fracking operations under local land-use ordinances.
North Carolina also received guidance from a multi-state organization called STRONGER — State Review of Oil and Natural Gas Environmental Regulations. It is made up of representatives from the oil and gas industry, environmental organizations, and state regulators. It develops guidelines and has review teams to evaluate state programs against those guidelines. The organization’s fracking guidelines developed in recent years were revised last year.
At the federal level, the EPA has been looking to regulate air emissions related to fracking. In the summer of 2012, the agency came out with a rule under the Clean Air Act dealing with well completions and the volatile organic compounds that come back up with the fracking chemicals, Byers said. EPA issued a “New Source Performance Standard” taking effect in 2015 that says well operators will have to separate out the gaseous air emissions from the liquids flowing back to the surface.
Byers also said that the EPA is invoking a concept under the Clean Air Act called aggregation. That means if a facility or a group of facilities in the same industrial code are operated on contiguous property and owned by the same party and are somehow connected, such as pipelines connecting different wells, then all of those emissions sources may be considered as one source. Their cumulative emissions can then be combined or “aggregated” to determine if they exceed major source permitting thresholds.
“The risk to well developers is that this will trigger a more involved permitting process,” Byers said. “A major source of emissions has to go through a more in-depth analysis, looking at best available control technology, and it may even require some air emissions dispersion modeling.”
But while the agency has been pushing forward with these Clean Air Act requirements, its progress has been slowed by legal challenges, Byers explained. “In 2012, EPA’s aggregation concept was invalidated by one of the federal appellate courts, and its subsequent attempt to continue applying this concept elsewhere was thwarted by the D.C. Circuit Court last May. Last year, EPA asked another federal appellate court to suspend litigation while it ‘reconsidered’ (revised) its New Source Performance Standards, which were released July 1,” Byers said.
Since the handling and disposal of the fracking fluids is perhaps the biggest environmental issue, drilling companies need to get a handle on their water footprint, Gooding said. The companies need to evaluate the issue in terms of dollar value, volume, and the complexity of the permitting process. Operators should consider options for reducing their water footprint. They should also consider how drought conditions may affect water availability.
Also on the federal level, the U.S. Department of the Interior (DOI) was working on a rule to require the disclosure of chemicals used in hydraulic fracturing on public lands. DOI got pushback from the states and Native American tribes who said that the proposal would just duplicate existing state requirements. The proposed rule was withdrawn and a new version was issued in 2013.
Samuel Glasser is editor, Global Marketing & Communications, with Black & Veatch. Contact Black & Veatch subject matter experts Andy Byers at firstname.lastname@example.org; Jim Gooding at email@example.com; and Mike Donnelly at firstname.lastname@example.org.