Independent Panel Formed to Review EPA Hydraulic Fracturing Report

On March 25, 2013, the EPA Independent Scientific Advisory Board (“SAB”) announced that it had formed the Hydraulic Fracturing Research Advisory Panel to review forthcoming EPA research on hydraulic fracturing.

The panel is composed of 31 experts, chosen from public nominations of scientists and engineers with experience and expertise related to hydraulic fracturing. As required by law, SAB screened candidates for conflicts of interest and appearance of lack of impartiality, and reviewed public comments, financial disclosure forms, and additional information submitted by the candidates.

The panel will peer review a forthcoming EPA draft report on potential health and environmental impacts of hydraulic fracturing on drinking water resources. 

The report is scheduled to be completed in 2014. EPA issued a Progress Report in December 2012, outlining the purpose of the study and the scope of its research efforts. In May 2013, the panel will convene to review public comments on the Progress Report and provide its own feedback to the EPA. The EPA will consider this feedback in preparation of its draft report.

This article was prepared by Lauren Brogdon ( or 713 651 5375) from the firm's litigation practice.

University of Tennessee Wins Approval for Hydraulic Fracturing Plan

On March 15, 2013, the Tennessee State Building Commission voted unanimously to approve a proposal by the University of Tennessee that would allow private natural gas drilling in Cumberland Forest, an area owned by the university.

The University intends to use the revenue from the natural gas activities to fund a research program into the effects of hydraulic fracturing and gas extraction. The school’s Institute of Agriculture is leading a “science-based investigation,” which will examine water quality, geology, air quality, terrestrial ecosystems, and best management practices and education.

The Building Commission vote allows the university to release a request for bids seeking an industry partner for the project. After a company’s bid is selected, the contract would be subject to Commission approval.

Since 1991, approximately 250 acres in the Cumberland Forest have been subject to a separate oil and gas lease. 

The lease generates $6,700 in annual revenue, which funds “upkeep and protection of the property” including “land surveys, forest fire protection equipment, [and] construction/improvement of roads,” according to the University

The University has no plans to enter into oil and gas leases on any additional properties.

This article was prepared by Lauren Brogdon ( or 713 651 5375) from Fulbright’s Litigation practice.

Gov. Brown Wants California to Consider Hydraulic Fracturing

At a renewable energy conference in San Francisco on March 13, 2013, Gov. Jerry Brown offered a qualified endorsement of hydraulic fracturing. Gov. Brown stated that “the fossil fuel deposits in California are incredible. The potential is extraordinary, but between now and development lies a lot of questions [concerning hydraulic fracturing’s effects on air and water quality] that need to be answered.” He advised that any decisions on fracking would be based on science, common sense and on a deliberative process that “listens to the people but also wants to take advantage of the great opportunities” in the state.

While hydraulic fracturing has been practiced for years in California oil patch, the development of the potentially lucrative Monterey shale formation has created the possibility of a new fracking boom in central California. Meanwhile, under discussion are hydraulic fracturing regulations proposed by California’s Division of Oil, Gas and Geothermal Resources (DOGGR) in December 2012 and several hydraulic fracturing bills that have been proposed in California’s legislature. Brief summaries of the proposed regulations and pending legislation follows.

California's DOGGR's proposed Hydraulic Fracturing Regulations

  • Fracking activities would not be considered underground injection or disposal projects and therefore would not be subject to statutes governing these projects. 
  • Operators would be required to:
    • Follow general requirements for well casing, protection of water zones, prevention of vertical migration of fluids or gases, wellbore integrity, and other well construction matters that are set out in the regulations. 
    • Provide the DOGGR and the appropriate water control board a variety of information detailing the proposed fracking operations before they begin. This information must be provided to the DOGGR on a required form at least ten days before fracking begins, and the DOGGR must post this to its website within seven days of receipt. The operator then must notify the DOGGR at least 24 hours before actually beginning the work. 
    • Pressure test all cemented casing strings and tubing strings, evaluate the adequacy of the cementing, insure proper rigging of the surface equipment, and perform a fracture radius analysis before commencing fracking operations. 
    • Monitor the wells after fracking has been completed to identify any potential problems that could endanger any underground source of protected water. The monitoring data must be maintained for at least five years and made available to the DOGGR. 
    • Post on specified data about the fracking operations, including identification of all fracking fluid components. Trade secrets need not be identified if the operator executes a declaration under penalty of perjury confirming the confidential nature of the information. Should an agency need to know the composition of the fluids claimed as trade secrets due a release or an accidental spill or should a medical professional need the information for treatment of a patient, the trade secret information must be provided. 
  • Monitoring would be required during the hydraulic fracturing activity. 
  • Fracking fluids, including fluids stored at well sites and fracking flowback must be stored in lined sumps or pits. Any unauthorized release of fluids must be reported to the DOGGR and the area of the release must be cleaned up and remediated. 

Senate Bill No. 4, introduced on December 3, 2012, amended on March 11, 2013
Assembly Bill No. 7, introduced on December 3, 2012

  • Defines “hydraulic fracturing” as a treatment used in stimulating a well that involves the pressurized injection of hydraulic fracturing fluid and proppant into an underground geologic formation in order to fracture the formation, thereby causing or enhancing the production of oil or gas from a well. Defindes “hydraulic fracturing fluid” as a carrier fluid mixed with physical and chemical additives tor the purpose of hydraulic fracturing. 
  • Operators would be required to 
    • Record and include all data on hydraulic fracturing treatments, including names and locations of all known seismic faults. 
    • File a notice of intention to commence fracking with the DOGGR supervisor or a district deputy at least 30 days before beginning the fracking operation. The hydraulic fracturing operation must be completed within one year of the filing of the notice of intention. Within 10 of receipt of the notice of intention, the DOGGR must make the notice publicly available by posting it on the division’s website and notifying the appropriate regional water quality control board 
  • A supplier (defined as an entity performing hydraulic fracturing or an entity supplying an additive or proppant directly to the operator for use in hydraulic fracturing) must provide the operator within 30 days following the conclusion of the fracking, detailed information regarding the hydraulic fracturing fluid. The information would include CAS numbers, maximum concentrations in percent by mass of each and every chemical constituent of the fluids used, the trade name, the total volume of base fluid, and the source, volume and disposition of all water. A supplier would not disclose trade secrets to the operator, but would be required to disclose the composition of any trade secret to the DOGGR. Within 60 days following the conclusion of fracking, the operator would be required to post the fracking fluid information on an Internet website accessible to the public. 
  • On or before January 1, 2015, the DOGGR, in consultation with the Department of Toxic Substances Control, the State Air Resources Board, and the State Water Resources Board, is directed to adopt rules and regulations specific to hydraulic fracturing, including provisions governing the construction of wells and well casings and full disclosure of the composition and disposition of hydraulic fracturing fluids. 

Senate Bill No. 395, introduced on February 20, 2013 

  • Defines “produced water” as any water brought up from the hydrocarbon bearing formation strata during the extraction of oil and gas, including hydraulic fracturing operations, and can include formation water, injection water, and any chemicals added downhole or during the oil and water separation process. 
  • Produced water is to be regulated as a hazardous waste. 

Assembly Bill No. 892, introduced on February 22, 2013

  • Defines “hydraulic fracturing” as the injection of fluids or gases into an underground geologic formation with the intentional to cause or enhance fractures in the underground geologic formation in order to cause or enhance the production of oil or gas from a well. 
  • Operator must provide a groundwater monitoring plan for review and approval by the supervisor and appropriate water quality control board. The plan must include the current water quality of the groundwater basin through which the well will be drilled, water quality data, a means to detect any contamination associated with well operation, and how to deal with a well casing failure or any other event which could contaminate the groundwater. 
  • Water quality monitoring must be submitted electronically to the State Water Resource Control Board and any other public data registry. 

This post was prepared by Barclay Nicholson ( or 713 651 3662) fromFulbright's Energy Practice.

Texas Railroad Commission Vote on Recycling Rules Expected Soon

On March 6, 2013, during a panel discussion on the management of community impacts of unconventional oil and gas development, Texas Railroad Commission Chairman Barry Smitherman indicated that by the end of the month, the Commission will issue rules to make it easier for drillers to recycle hydraulic fracturing flowback water at the drilling sites.

Smitherman expected the rules to clarify what materials can be recycled and provide baseline specifications for fracking fluid recycling pits.

As mentioned in our 3/11 Fracking Blog post, Flowback Fluid Recycling Regulation in the Barnett and Eagle Ford Shale Plays, the Commission has proposed that recycling be allowed onsite without a permit if the waste water is to be re-used in the fracking operations or treated to drinking water quality and disposed of appropriately.

According to TRRC Chairman, the Commission will consider and vote on the proposed recycling rules at its next scheduled hearing on March 26, 2013.

This post was prepared by Barclay Nicholson ( or 713 651 3662) fromFulbright's Energy Practice.

New York Assembly Approves Two-Year Moratorium on Hydraulic Fracturing

On March 6, 2013, the New York State Assembly voted to place a temporary moratorium on all permits for high-volume hydraulic fracturing gas wells until May 2015. The bill was sponsored by Assembly Committee on Environmental Conservation Chairman Kevin K. Sweeney, and would extend a de facto moratorium that has existed in New York for over four years.

The bill also calls for the State University of New York to conduct an independent health review of the effects of hydraulic fracturing.

The bill will be brought before the New York Senate and, if approved there, will be sent to New York Governor Andrew Cuomo for final approval. 

On March 5, 2013, Democratic members of the New York Senate introduced a bill that would require the state to wait to rule on whether hydraulic fracturing should be banned until after the U.S. EPA releases its final study on the effects of the process on drinking water, and the New York Health Commissioner reviews the results of a similar study conducted by the Geisinger Health System, a health care company in Pennsylvania.

This article was prepared by Lauren Brogdon ( or 713 651 5375) from Fulbright’s Litigation Practice Group.

Flowback Fluid Recycling Regulation in the Barnett and Eagle Ford Shale Plays

This article is part of a series of blog posts evaluating the current status of flowback and produced water recycling regulations in the major shale play states. These waters are generated through the hydraulic fracturing process, and this blog series will discuss the manner in which these waters are disposed.

 Flowback and produced waters from the hydraulic fracturing process may be disposed of in a number of ways. First, they may be injected into permitted disposal wells. Second, they could be delivered to permitted water treatment facilities. Or third, they are recycled. Recycling this flowback fluid that returns to the surface after hydraulic fracturing, as well as the naturally occurring produced water, is especially useful when fresh water is in short supply.

As shale plays located solely within the Texas borders, the Barnett and Eagle Ford shale plays are subject to Texas’ commercial recycling regulations. The Railroad Commission of Texas (“RRC”) regulates wastewater management from oil and gas development and the Texas Commission on Environmental Quality (“TCEQ”) regulates wastewater treatment facilities. However, the current set of rules do not contemplate the recycling of flowback fluids.

The Wall Street Journal recently pointed out that recycling the water used in hydraulic fracturing operations could be a billion dollar market due to the way it will cut costs for energy companies. State regulators are also taking note of the beneficial environmental impacts and developing rules to encourage flowback fluid and produced water recycling.

In February, 2012 the RRC distributed a draft of proposed amendments to its commercial recycling rules. It also solicited informal comments and held a workshop for interested parties in order to get feedback on the proposed changes. The RRC then used the feedback to release the proposed rules on September 28, 2012. The comment period ended on October 29, 2012.

The main impetus behind the rules was the increasing number of permit applications for facilities that did not fall into either type of commercial recycling facility (mobile facilities and stationary facilities) under the existing rules. Thus, the RRC proposes a third category, for semi-mobile commercial recycling facilities. The new rules, as a result, make it much easier to conduct on-lease, non-commercial recycling of produced water and/or hydraulic fracturing flowback fluid. They also include requirements for off-lease or centralized non-commercial produced and flowback fluid recycling.

Under the new rules, non-commercial on-lease produced water and/or hydraulic fracturing flowback fluid recycling could be conducted without a permit if the fluids are either:
  1. recycled for use as hydraulic fracturing fluid or other oilfield fluid to be used in the wellbore of an oil, gas, geothermal, or service well; or 
  2. treated to national drinking water standards under the Safe Drinking Water Act and used in any way other than as a discharge to surface water or in the irrigation of edible crops.  

The proposed rules also establish standards for the construction and operation of recycling pits holding produced water and/or flowback fluid. The rules specify particular siting, lining, and capacity requirements for such impoundments. Upon adoption, commercial recycling activities associated with hydraulic fracturing could be more easily conducted.

This article was prepared by Heather M. Corken ( or 713 651 8386) and Kristen Hulbert ( or 713 651 5303) from Fulbright's Environmental Law Practice Group.

Texas Railroad Commission Revises Proposed Rules Relating to Casing, Cementing, Drilling, and Completion Requirements

On January 29, 2013, the Texas Railroad Commission (RRC) withdrew previously proposed amendments to the Administrative Code relating to:
  1. casing, cementing, drilling, and completion requirements, 
  2. cathodic protection wells, and 
  3. seismic holes and core holes (16 Tex. Admin. Code §§ 3.13, 3.99, and 3.100 respectively). 
These proposed changes were published in the Texas Register on February 15, 2013 and will be open for public comment until April 1, 2013.

Important provisions include:
  1. “Potential flow zone” is a new term which refers to “a zone designated by the director or identified by the operator…that needs to be isolated to prevent sustained pressurization of the surface case, intermediate casing, or production casing annulus sufficient to cause damage to casing and/or cement in a well such that it presents a threat to subsurface water or other subsurface resources, or sufficient to cause the fluids in the annulus to maintain a static fluid level at or less than 250 vertical feet below the protection depth.” 
  2. The diameter of the wellbore in which surface casing will be set and cemented must be at least 1.5 inches greater than the nominal outside diameter of the casing. For subsequent casing strings, the diameter of each section of the wellbore for which casing will be set and cemented must be at least 1 inch greater than the nominal outside diameter of the casing to be installed. 
  3. Casing 
    • All casing cemented in any well must be steel casing that has been hydrostatically pressure tested with an applied pressure at least equal to the maximum pressure to which the pipe will be subjected in the well. 
    • Casing must be cemented across and above all formations permitted for injection under § 3.9 (Disposal Wells) or § 3.46 (Fluid Injection into Productive Reservoirs) within 1/4 mile radius of the well to be drilled. 
    • Casing must be cemented across and above all productive zones, potential flow zones, and zones with corrosive formation fluids. 
    • Notice must be given to and approved by the district director before setting casing to a depth of 3,500 feet or greater. 
  4. Hydraulic fracturing 
    • All casing installed in a well that will be subjected to hydraulic fracturing treatments shall have a minimum internal yield pressure rating of at least 1.15 times the maximum pressure to which the casing may be subjected. 
    • The operator must pressure test the casing (or fracture tubing) on which the pressure will be exerted during hydraulic fracturing treatments to at least the maximum anticipated pressure. The district director must be advised of a failed test within 24 hours of completion of the test. 
    • During hydraulic fracturing operations, the operator must monitor all annuli. All operations must be suspended if the pressure deviates above anticipated increases caused by pressure or thermal transfer. The district director must be notified within 24 hours of that deviation and must give his approval before operations can recommence. 
  5. Blowout prevention 
    • A blowout preventer system or control head and other connections must be installed as soon as surface casing is set. 
    • Ram type blowout prevention equipment must be tested to at least the maximum anticipated surface pressure of the well, but not less than 1,500 psi, before drilling the plug on the surface casing and before encountering any high-pressure formations. 
    • Blowout prevention equipment must be tested upon installation, after the disconnection or repair of any pressure containment seal in the blowout preventer stack, choke line, or choke manifold, with testing to occur at least every 21 days. 
  6. A drilling fluid program is established to provide detail on the characteristics, use, and testing of drilling fluid. 
  7. Within 30 days of the well’s completion or within 90 days of cessation of drilling operations, whichever is earlier, a cementing report must be filed with the commission. 
Read the proposed amendments to the Texas Railroad Commission Rules.

This post was prepared by Barclay Nicholson ( or 713 651 3662) from Fulbright's Energy Practice.

Railway Considers Natural Gas to Fuel Locomotives

BNSF Railway Company, the largest railroad in the U.S. and the second biggest user of diesel fuel in the country, announced that it plans to test using natural gas to power its locomotives later this year. In the late 1980s, BNSF considered a switch to natural gas, but shelved the plan when natural gas prices rose. Now, with the glut of cheap natural gas in North America coming from the development of natural gas deposits in shale formations, the switch to natural gas is more appealing.

According to federal statistics, a gallon of diesel cost an average of $3.97 last year while the equivalent in natural gas cost 48 cents at industrial prices. This price does not reflect the costs of cooling the natural gas into a dense energy-packed liquid or the upfront costs of retrofitting BNSF’s fleet of approximately 6,900 locomotives. It is estimated that retrofitting a diesel locomotive and adding a tanker car could add 50% to a locomotive’s $2,000,000 price tag. In addition, the potential shift must be approved by federal regulators on fuel-tank safety and would require different fuel depots, special tanker cars, and training for depot workers. 

Still, BNSF, a subsidiary of Warren Buffet’s Berkshire Hathaway, Inc., believes that natural gas has the potential to be significantly less expensive than diesel for years to come. In addition to the low price of natural gas fuel, BNSF is considering the switch because of recent Environmental Protection Agency air pollution standards for railroads that require diesel locomotives to have expensive emissions-control equipment by 2015.

BNSF’s pilot trains are expected to roll out in the fall of 2013. If the pilot program proves reliable and effective, retrofitting of existing locomotives could begin in the fall of 2014. BNSF is working with General Electric Company and Caterpillar, Inc. to develop a locomotive that can run on diesel and gas. Last September, Canadian National Railway Company (CNRC) retrofitted two locomotives to run on 90% LNG and 10% diesel. CNRC has indicated that it is “too early to determine if the pilot program was successful.”

Experts believe that it would take at least 5 years for gas-powered locomotives to be a significant presence on the rails. Nevertheless, the possible switch has created numerous discussions about increasing the use of natural gas in the transportation industry, including long-haul trucking and municipal bus fleets.

This article was prepared by Barclay R. Nicholson ( or 713 651 3662) from Fulbright's Energy Practice.

Germany Drafts Hydraulic Fracturing Regulations

On Tuesday, February 26, 2013, the German government proposed new regulations concerning the recovery of hydrocarbons through hydraulic fracturing. These new regulations come at a point when several European governments have imposed a ban on hydraulic fracturing. 

The proposed regulations would outlaw fracking in areas where there are water reserves and mineral springs and in areas near drinking water wells. All new projects would require environmental impact studies. Economy Minister Philipp Roesler stated that, while fracking offers “significant opportunities, we must always keep in view possible effects on the environment. ” 

Environment Minister Peter Altmaier indicated that the proposed regulations represented “an important breakthrough to contain the dangers of fracking. Safety and environmental protection have priority over economic interests.” Chancellor Angela Merkel has expressed concern about hydraulic fracturing in her densely populated country, but indicated the need to develop domestic energy sources as Germany closes its nuclear power plants, shifts to renewable energy, and wants to become less reliant on Russian gas. 

With German elections set for September, fracking has become a “bone of contention” between the political parties. Opposition parties have called either for a temporary moratorium (Social Democrats) or a complete ban (Green Party) on fracking.

According to the Federal Institute for Geosciences and Natural Resources, Germany may have as much as 2.3 billion cubic meters (81 billion cubic feet) of shale gas under its surface, a significant source of future energy. Developing that gas could boost the current output of natural gas 100-fold some experts suggest. Gas prices in Germany are currently four times those in the U.S.