In an April 1, 2014 memorandum, the U.S. Environmental Protection Agency (EPA) summarized state regulatory programs concerning the management of solid waste from oil and natural gas exploration, development and production (E&P) operations.
In reviewing each state’s regulations, the EPA focused on surface storage and disposal facilities managing produced waters, drilling muds, drilling cuttings, hydraulic fracturing return fluids, and various other waste liquids and materials intrinsically related to oil and gas E&P.
The EPA found that the state regulations were primarily concerned with the “technical requirements associated with the design, construction, operation, maintenance, closure, and reclamation of surface pits, ponds, lagoons or tanks, as well as financial assurance requirements associated with such facilities.”
Among the common parameters are state requirements for liners in pits and impoundments, secondary containment requirements for tanks, set-back requirements, and various inspection requirements. However, the EPA did find gaps in regulations relating to groundwater monitoring, leachate collection, air monitoring, and waste characterization.
Overall, with the review, the EPA had developed an understanding of the wide-range of state regulatory programs currently in place in the twenty-six (26) oil and gas producing states covered in the summary.
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Showing posts with label Louisiana. Show all posts
Showing posts with label Louisiana. Show all posts
Senators question EPA’s proposed research into states’ efforts to regulate hydraulic fracturing
In a letter dated May 8, 2014, five U.S. senators urged the Office of Inspector (OIG) of the U.S. Environmental Protection Agency (EPA) to discontinue its “preliminary research on the EPA’s and states’ ability to manage potential threats to water resources from hydraulic fracturing,” arguing that such a review is “well outside the mission and expertise of the OIG…[and] duplicative of numerous other federal efforts.”
The OIG announced its proposed research in a memorandum dated February 5, 2014, stating that it would evaluate the regulatory authority that is available to the EPA and the states, identify potential threats to water resources from fracturing operations, and evaluate how the EPA and the states have responded to these threats. According to the OIG, this research would improve preventative and response measures and improve coordination among the EPA, states and industry to ensure that water resources are protected.
The senators from Louisiana, Oklahoma, and Texas complain that the EPA has previously “conducted a number of indisputably flawed and unscientific investigations attempting to link hydraulic fracturing to water contamination and has continued to come up empty handed.” Moreover, the senators state that, with this additional research, the EPA is trying to “manufactur[e] a need for new regulations on a production technique that has been safely and effectively regulated at the state level for the better half of a century.” According to the senators, only state regulators with knowledge and expertise of their state’s geology, ecology, and hydrology and who have a vested interest in protecting their state’s water supplies from contamination are qualified to tailor regulatory programs to meet their state’s needs.
Pointing to extensive studies of hydraulic fracturing from the Department of Energy, the Department of the Interior, the Government Accountability Office, and the EPA, the senators urge that this research be stopped and that the OIG focus on “a more relevant and needed inquiry into fraud, abuse, and waste at the EPA.”
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
The OIG announced its proposed research in a memorandum dated February 5, 2014, stating that it would evaluate the regulatory authority that is available to the EPA and the states, identify potential threats to water resources from fracturing operations, and evaluate how the EPA and the states have responded to these threats. According to the OIG, this research would improve preventative and response measures and improve coordination among the EPA, states and industry to ensure that water resources are protected.
The senators from Louisiana, Oklahoma, and Texas complain that the EPA has previously “conducted a number of indisputably flawed and unscientific investigations attempting to link hydraulic fracturing to water contamination and has continued to come up empty handed.” Moreover, the senators state that, with this additional research, the EPA is trying to “manufactur[e] a need for new regulations on a production technique that has been safely and effectively regulated at the state level for the better half of a century.” According to the senators, only state regulators with knowledge and expertise of their state’s geology, ecology, and hydrology and who have a vested interest in protecting their state’s water supplies from contamination are qualified to tailor regulatory programs to meet their state’s needs.
Pointing to extensive studies of hydraulic fracturing from the Department of Energy, the Department of the Interior, the Government Accountability Office, and the EPA, the senators urge that this research be stopped and that the OIG focus on “a more relevant and needed inquiry into fraud, abuse, and waste at the EPA.”
This post was written by Barclay Nicholson (barclay.nicholson@nortonrosefulbright.com or 713.651.3662) from Norton Rose Fulbright's Energy Practice Group.
Survey of Flaring Regs for Arkansas, Colorado, Louisiana, North Dakota, Pennsylvania, Texas and Wyoming
Natural gas production is booming in the United States.
Operators, aided by advances in hydraulic fracturing, have ramped up production, whether by reworking old oil wells or exploiting new formations altogether.
However, just because an operator has the ability to produce natural gas does not necessarily mean that it can sell the gas; compressors, pipelines, treatment plants, and other infrastructure must be prepared in order to get the gas to market.
However, just because an operator has the ability to produce natural gas does not necessarily mean that it can sell the gas; compressors, pipelines, treatment plants, and other infrastructure must be prepared in order to get the gas to market.
In some cases, this lack of infrastructure has led operators to vent or flare gas at the wellhead.
In order to get a better understanding of where the law stands and in what direction it may head, below is a survey of the major gas-producing states’ regulations regarding flaring.
Note: this survey covers only the regulations that speak directly to the question of whether an operator may flare the gas on private lands. Flaring has other potential legal repercussions, such as the particles that are emitted in the process that could call into question state or federal clean air laws or endangered species, and different regulations apply to wells located on state- or federally-owned land. Those concerns are beyond the scope of this survey.
Arkansas
Arkansas allows operators to vent or flare gas within 7 days of when gas is first encountered in a well. After that time, gas may not be vented or flared unless the operator obtains an exception from the Arkansas Oil and Gas Commission.Colorado
In Colorado, all flaring must be authorized by the Colorado Oil and Gas Conservation Commission unless it is done during an upset condition, well maintenance, well stimulation flowback, purging operations, or a productivity test.Louisiana
In Louisiana, flaring of natural gas is prohibited unless the Louisiana Office of Conservation finds upon written application that such a prohibition would result in an economic hardship on the operator. The regulations further note that no such economic hardship can be found if the current market value—at the point of delivery for the gas proposed to be vented—exceeds the cost involved in making the gas available to market.North Dakota
Gas may be flared during the first year of production from a well. N.D. Century code 38-08-06.4. After the one-year grace period, the well must be either connected to a pipeline or used at the wellhead to power an electrical generator, unless the producer applies for and obtains an exception. Id.
Producers can obtain exceptions from the Industrial Commission for additional flaring if the producer presents evidence demonstrating the economic infeasibility of piping gas from the well. Id.
It is economically infeasible to connect the well to a natural gas gathering line if the direct costs of connecting the well to the line and the direct costs of operating the facilities connecting the well to the line during the life of the well are greater than the amount of money the operator is likely to receive for the gas, less production taxes and royalties, should the well be connected to the gathering line. N.D. Century Code 43-02-03-60.2.
Oklahoma
In Oklahoma, an operator may vent or flare up to 50 mcf/day without a permit if: (i) it is not economically feasible to market the gas; (ii) a suitable stand, line, or stack is used to prevent a hazard to people; and (iii) there is less than 100 ppm of hydrogen sulfide in the gas. For venting or flaring at rate greater than 50 mcf/day, the operator must seek an administrative permit from the Conservation Division of the Oklahoma Corporation Commission.Pennsylvania
Pennsylvania’s oil and gas conservation regulations do not address flaring, other than to say that it may be done so long as it does not endanger people.Texas
Texas producers have a grace period of 10 days after the initial completion, recompletion in another field, or workover operations in the same field, during which they may flare natural gas. 16 TAC 3.32(f)(1)(A). Releases of gas that are not routinely measured (such as small amounts that escape during the initial completion of a well) are exempt from flaring requirements and need not be measured for the purposes of well allowables. 16 TAC 3.32 (d)(1).
Producers may also vent or flare gas when a well must be unloaded or cleaned-up to atmospheric pressure, but may only do so for fewer than 24 hours in one continuous event or a total of 72 hours in one calendar month. 16 TAC 3.32(f)(1)(B). Texas producers may obtain exceptions from the railroad commission for the release of gas when the operator presents information to show the necessity of the release. 16 TAC 3.322(f)(2).
However, such administrative exceptions shall not be granted for periods exceeding 180 days, though they may be renewed. 16 TAC 3.32(h).
Wyoming
Wyoming allows for flaring without any additional regulatory authorization in the following situations:- During emergencies or upset conditions, which are temporary situations that result in the unavoidable short-term venting or flaring of gas;
- For well purging and evaluation tests;
- During initial or recompletion evaluation tests which shall not exceed 15 days unless otherwise authorized; or
- If it is a venting or flaring of casinghead gas from an oil well that produces less than 60 MCF of gas per day, unless the Wyoming Oil & Gas Conservation Commission determines that waste is occurring.
Texas RRC Press Release, May 23, 2012
Texas Railroad Commissioner David Porter discussed the possibility of new regulations in a May 23 news release. Noting that gas drilling activity “is outstripping capacity and awaiting pipeline infrastructure,” Commissioner Porter asserted that Texas “must proactively address flaring.” The only specifics provided in the news release were:
- that the Railroad Commission is seeking to work in partnership with Texas electrical energy regulators to use excess gas for strategic generation in light of the threat of weather-induced power curtailment; and
- that the Railroad Commission is studying a pilot program for using gas as a source of power for on-lease operations in lieu of flaring the gas.
This article was prepared by Barclay Nicholson (bnicholson@fulbright.com / 713 651 3662) from Fulbright's Energy Law Practice.
FERC Approves Sabine Pass LNG Exports and Vacates Jordan Cove LNG Imports
The Sabine Pass Liquefaction Project will be constructed at the existing Sabine Pass LNG, L.P. terminal in Cameron Parish, Louisiana.
Upon completion of the Liquefaction Project, the Sabine Pass terminal will be the first bi-directional LNG facility in the U.S., capable of importing and regasifying foreign-sourced LNG, and liquefying and exporting domestically produced natural gas as LNG. FERC’s approval follows the DOE authorization last year enabling Sabine Pass Liquefaction, LLC to export domestically produced LNG for a 20-year period to all U.S. trading partner countries.
In the same sweep, FERC surprised industry watchers by vacating, without prejudice, an order previously authorizing Jordan Cove Energy Project, L.P. (“Jordan Cove”) to construct and operate an LNG import terminal in Coos County, Oregon along with the related pipeline certificate authorization for the proposed 234-mile-long Pacific Connector pipeline.
The Commission seemed to base its decision to vacate those prior approvals on recent statements by Jordan Cove that it did not intend to construct and operate its authorized import facilities at this time in light of current market conditions, but rather was seeking authorization to construct LNG export facilities.
In a strongly worded dissent, Commissioner Philip Moeller noted that FERC chose to vacate the Jordan Cove authorization “based upon little more than statements about current market conditions by Jordan Cove and the market views of three Commissioners.”
Commissioner Moeller further stated that “[r]evoking an authorization to build during the third year of a five-year authorization could fundamentally change how the public views whether this Commission will stand by its decisions.”
In conclusion, FERC’s authorization of the Liquefaction Project signals that export projects may lead the next wave of LNG development in the U.S. for those project sponsors able to obtain DOE export approval.
While the Commission’s decision with respect to the Jordan Cove import project and the Pacific Connector pipeline undoubtedly will become part of any LNG regulatory risk dialogue, we do not believe that FERC’s decision should be interpreted as a death blow for all LNG import capacity development.
Rather, we believe the FERC has put developers on notice that proposals for LNG import capacity will have to address existing U.S. market conditions that strongly support exports, but which also may vary by region.
Thus, LNG developers are well advised to design their projects in a manner that takes into account changing market conditions. For this reason, a bi-directional facility, such as the Sabine Pass terminal, is well positioned to withstand regulatory challenges based on changing market conditions.
This article was prepared by Lisa M. Tonery (ltonery@fulbright.com or 212 318 3009), Tania S. Perez (tperez@fulbright.com or 212 318 3147) and Rabeha Kamaluddin (rkamaluddin@fulbright.com or 202 662 4576) of the Fulbright's Energy practice.
Texas, Other States Move Forward With Hydraulic Fracturing Disclosure Regulations
Earlier this year, Texas became the latest state to draft regulations requiring the disclosure of chemicals used in the hydraulic fracturing process. Michigan and Montana issued similar regulations over the summer, joining Arkansas, Wyoming, and Pennsylvania as states recently active in regulating hydraulic fracturing.[1] The new regulations require specific disclosures by operators and outline requirements for construction and operation of the well and continued monitoring of well activity. Three additional states, Louisiana, New York, and North Dakota, have proposed regulations open for public comment. This briefing examines recent changes and additions in hydraulic fracturing regulations throughout the country.
On October 11, 2011, the public comment period closed for the proposed hydraulic fracturing chemical disclosure regulations issued by the Railroad Commission of Texas. The Railroad Commission issued the new regulations on September 9, pursuant to HB 3328, passed by the Texas Legislature in June.[2] HB 3328 requires that the approved regulations be effective by July 1, 2012; however, it is expected that regulations will be finalized by the end of the year.
The proposed Texas regulations require public disclosure of chemicals used in the fracturing process that are either regulated by OSHA or are otherwise intentionally added, along with the actual or maximum concentrations of each chemical.[3]
Michigan's Supervisor of Wells issued new regulations in May 2011, which became effective June 22, 2011.[4] Under the regulations, well completions for high volume hydraulic fracturing must include the Material Safety Data Sheet and the volume used for all additives. High volume hydraulic fracturing is defined as an operation that is intended to use a total of more than 100,000 gallons of hydraulic fracturing fluid.
Additional regulations apply to wells with large volume water withdrawals, defined as withdrawals with a cumulative total of over 100,000 gallons per day. For these wells, permit applications must include: a water withdrawal evaluation (and in some cases a site-specific review by the DEQ); the proposed total volume of water needed; the number of water withdrawal wells; well locations, depths, and proposed pumping rates and frequencies; any freshwater wells within 1,320 feet; and the locations and dimensions of proposed freshwater pits.
Texas: Public Comment Period Closed
On October 11, 2011, the public comment period closed for the proposed hydraulic fracturing chemical disclosure regulations issued by the Railroad Commission of Texas. The Railroad Commission issued the new regulations on September 9, pursuant to HB 3328, passed by the Texas Legislature in June.[2] HB 3328 requires that the approved regulations be effective by July 1, 2012; however, it is expected that regulations will be finalized by the end of the year.
The proposed Texas regulations require public disclosure of chemicals used in the fracturing process that are either regulated by OSHA or are otherwise intentionally added, along with the actual or maximum concentrations of each chemical.[3]
Companies would be required to use Chemical Abstracts Service (CAS) numbers to identify chemicals in the fracturing fluids, making the disclosure more transparent for shippers, suppliers, end users, and the public. The regulations specifically exempt from disclosure chemicals unintentionally added, chemicals that occur naturally, or chemicals not disclosed by the manufacturer, supplier, or service company.
Companies can also claim trade secret exemptions, which must be approved by the Railroad Commission. If a trade secret exemption is granted, only three parties can challenge it:
- the landowner on whose property the wellhead is located;
- any adjacent property owners; and
- government agencies.
Michigan: Regulations Effective June 22, 2011
Michigan's Supervisor of Wells issued new regulations in May 2011, which became effective June 22, 2011.[4] Under the regulations, well completions for high volume hydraulic fracturing must include the Material Safety Data Sheet and the volume used for all additives. High volume hydraulic fracturing is defined as an operation that is intended to use a total of more than 100,000 gallons of hydraulic fracturing fluid.
Additional regulations apply to wells with large volume water withdrawals, defined as withdrawals with a cumulative total of over 100,000 gallons per day. For these wells, permit applications must include: a water withdrawal evaluation (and in some cases a site-specific review by the DEQ); the proposed total volume of water needed; the number of water withdrawal wells; well locations, depths, and proposed pumping rates and frequencies; any freshwater wells within 1,320 feet; and the locations and dimensions of proposed freshwater pits.
If there is a freshwater well within 1,320 feet, a monitor well must be installed and monitored daily during water withdrawal, and weekly thereafter. During the withdrawal process, injection pressures must be recorded. Upon well completion, records and charts showing fracturing volume, rates, pressures, and the total volume of flowback water must be included in the record of well completion.
According to the Michigan Department of Environmental Quality, no current hydraulic fracturing activity in Michigan would qualify as high volume under the proposed regulations.[5]
According to the Michigan Department of Environmental Quality, no current hydraulic fracturing activity in Michigan would qualify as high volume under the proposed regulations.[5]
Existing wells, which are located on the Antrim Shale, are shallow and typically use only 50,000 gallons of water in the fracturing process. The regulations were implemented in anticipation of development on the Utica Shale, a deeper formation that would require much larger volumes of water use.
Montana: Regulations Effective August 27, 2011
The Montana Board of Oil and Gas issued new regulations that became effective August 27, 2011.[6] Under the Montana regulations, applications for permits must include the volumes and types of materials to be used in the proposed hydraulic fracturing activities. Principal components or chemicals must be identified by trade name or generic name.
Upon completion, fracturing operators must disclose the amounts and types of chemicals used, including the additive types, chemical ingredient names, and CAS numbers. Operators can qualify for trade secret exemptions, under which exempted chemicals must be identified by trade name, inventory name, chemical family name, or other unique name, and operators must disclose the quantity of the exempted chemical to be used. The regulations also require that permit applications include the processes to be used and the maximum anticipated treating pressure.
In addition to application requirements, the Montana regulations lay out specific structural and operational requirements. Fracturing wells must have a pressure relief valve and a remotely controlled shut-in device. Before stimulation, fracturing wells must undergo a casing pressure test. During the casing test, the maximum anticipated pressure must be applied for thirty minutes without the well losing more than ten percent of the pressure. Additionally, during operations, the annular space must be monitored. Upon completion, operators must describe the interval or formation treated and the amounts of maximum pressure during treatment.
In September 2011, the New York Department of Environmental Conservation issued extensive proposed regulations that outline permitting and operations requirements for hydraulic fracturing that uses more than 300,000 gallons of water cumulatively.[7] Under the proposed regulations, operators must follow the requirements of the application process for a normal drilling permit, as well as comply with State Pollutant Discharge Elimination System (SPDES) and Stormwater Pollutant Prevention (SWPP) plans. The New York regulations will be out for public comment through December 12, 2011.
To obtain a permit for hydraulic fracturing, operators must include the following information: the minimum and estimated maximum depths; the proposed volume of water and source of the water; distances from certain types of water supplies; identities of nearby abandoned wells; the engines and fuel to be used and air emission control measures; and information on blowout preventer measures. The New York regulations also contain detailed requirements for setbacks, water and pressure testing, casing structure, and construction, including site preparations and maintenance.
To comply with SPDES and SWPP requirements, operators must disclose particular information and submit plans aimed at preventing water contamination and sediment erosion. Operators must disclose: the proposed additives and each additive's proposed volume; copies of Material Safety Data Sheets for each product to be used; the proposed percent of water, proppants, and each additive product; documentation showing that the proposed additives have reduced aquatic toxicity and pose a lower potential risk to water resources and the environment than available alternatives (or that available alternative products are not equally effective or feasible); and the identification of the service company. Trade secret protection is available if granted by the Department of Environmental Conservation. Plans to prevent water contamination and sediment erosion require operators to continually monitor well activity, such as stormwater discharges, water usage, and flowback and produced water volumes. Operators must have certification for planned disposal methods, secondary containment measures, spill prevention plans, and methods to store flowback water.
On August 30, 2011, the Louisiana Department of Natural Resources released a proposed rule for public comment.[8] The rule requires operators upon well completion to disclose the types and volumes of the hydraulic fracturing fluid, a list of additives including trade names and suppliers, CAS numbers for hazardous chemicals, and maximum ingredient concentrations. The proposed rule has a provision for trade secret protection under which only the chemical family must be disclosed.
The Department of Natural Resources has not officially issued an anticipated effective date. According to reports, the rule is expected to become effective in October 2011.
The North Dakota Industrial Commission proposed new regulations for hydraulic fracturing on September 23, 2011.[9] Under the proposed rules, companies who do not use a frac string running inside the intermediate casing string must disclose the hydraulic fracturing fluid composition, including the trade name, supplier, ingredients, CAS number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. No disclosure is required for wells that use a frac string inside the intermediate casing string. The proposed rules also outline specific safety systems that must be used, including pressure relief valves, diversion lines, and remote operated frac valves. The North Dakota regulations are currently out for public comment, and a public hearing is scheduled for November 1.
This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) and Andrea Fair (afair@fulbright.com or 713 651 3782) from Fulbright's Litigation Department.
Learn more about Fulbright's Shale and Hydraulic Fracturing Task Force at www.fulbright.com/shale.
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[1] See 25 Pa. Code §78.55 (as part of the permitting process, drilling companies must disclose the names of all chemicals to be stored and used at a drilling site in the Pollution Prevention and Contingency Plan submitted to the Department of Environmental Protection); Wy. Oil & Gas Comm'n § 3-8(c) (operators must disclose chemical additives and proposed concentrations in the Application for Permit to Drill or Deepen). Ariz. Admin. Code § 12-7-117 (operators of wells using "artificial stimulation" must report the amount and types of material injected within 15 days of the procedure).
[2] HB 3328, 2011 Leg., 82 Sess. (TX 2011). For an in-depth analysis of HB 3328 and the proposed Texas disclosure requirements, see Texas Legislature Joins Growing Number of States in Requiring Disclosure of Hydraulic Fracturing Fluids, Fulbright Briefing (June 16, 2011).
[3] 36 Tex. Reg. 5765 (2011) (to be codified at 16 Tex. Admin. Code § 3.29) (proposed September 9, 2011) (Railroad Commission of Texas).
[4] Supervisor of Wells Instruction 1-2011, High Volume Hydraulic Fracturing Well Completions, State of Michigan Department of Environmental Quality (May 23, 2011).
[5] Keith B. Hall, Michigan Issues New Hydraulic Fracturing Regulations, Oil & Gas Law Brief, Stone Pigman Walther Wittmann L.L.C.
[6] Administrative Rules of Montana, Title 36, Chapter 22.
[7] N.Y. Comp. Codes R. & Regs. tit. 6, Parts 52, 190, 550–556, 560, 750
[8] LAC 43:XIX Subpart 1, Chapter 1.
[9] N.D. Admin. Code § 43-02-03-27.1.
In addition to application requirements, the Montana regulations lay out specific structural and operational requirements. Fracturing wells must have a pressure relief valve and a remotely controlled shut-in device. Before stimulation, fracturing wells must undergo a casing pressure test. During the casing test, the maximum anticipated pressure must be applied for thirty minutes without the well losing more than ten percent of the pressure. Additionally, during operations, the annular space must be monitored. Upon completion, operators must describe the interval or formation treated and the amounts of maximum pressure during treatment.
New York: Out for Public Comment
In September 2011, the New York Department of Environmental Conservation issued extensive proposed regulations that outline permitting and operations requirements for hydraulic fracturing that uses more than 300,000 gallons of water cumulatively.[7] Under the proposed regulations, operators must follow the requirements of the application process for a normal drilling permit, as well as comply with State Pollutant Discharge Elimination System (SPDES) and Stormwater Pollutant Prevention (SWPP) plans. The New York regulations will be out for public comment through December 12, 2011.
To obtain a permit for hydraulic fracturing, operators must include the following information: the minimum and estimated maximum depths; the proposed volume of water and source of the water; distances from certain types of water supplies; identities of nearby abandoned wells; the engines and fuel to be used and air emission control measures; and information on blowout preventer measures. The New York regulations also contain detailed requirements for setbacks, water and pressure testing, casing structure, and construction, including site preparations and maintenance.
To comply with SPDES and SWPP requirements, operators must disclose particular information and submit plans aimed at preventing water contamination and sediment erosion. Operators must disclose: the proposed additives and each additive's proposed volume; copies of Material Safety Data Sheets for each product to be used; the proposed percent of water, proppants, and each additive product; documentation showing that the proposed additives have reduced aquatic toxicity and pose a lower potential risk to water resources and the environment than available alternatives (or that available alternative products are not equally effective or feasible); and the identification of the service company. Trade secret protection is available if granted by the Department of Environmental Conservation. Plans to prevent water contamination and sediment erosion require operators to continually monitor well activity, such as stormwater discharges, water usage, and flowback and produced water volumes. Operators must have certification for planned disposal methods, secondary containment measures, spill prevention plans, and methods to store flowback water.
Louisiana: Out for Public Comment
On August 30, 2011, the Louisiana Department of Natural Resources released a proposed rule for public comment.[8] The rule requires operators upon well completion to disclose the types and volumes of the hydraulic fracturing fluid, a list of additives including trade names and suppliers, CAS numbers for hazardous chemicals, and maximum ingredient concentrations. The proposed rule has a provision for trade secret protection under which only the chemical family must be disclosed.
The Department of Natural Resources has not officially issued an anticipated effective date. According to reports, the rule is expected to become effective in October 2011.
North Dakota: Out for Public Comment
The North Dakota Industrial Commission proposed new regulations for hydraulic fracturing on September 23, 2011.[9] Under the proposed rules, companies who do not use a frac string running inside the intermediate casing string must disclose the hydraulic fracturing fluid composition, including the trade name, supplier, ingredients, CAS number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. No disclosure is required for wells that use a frac string inside the intermediate casing string. The proposed rules also outline specific safety systems that must be used, including pressure relief valves, diversion lines, and remote operated frac valves. The North Dakota regulations are currently out for public comment, and a public hearing is scheduled for November 1.
This article was prepared by Barclay R. Nicholson (bnicholson@fulbright.com or 713 651 3662) and Andrea Fair (afair@fulbright.com or 713 651 3782) from Fulbright's Litigation Department.
Learn more about Fulbright's Shale and Hydraulic Fracturing Task Force at www.fulbright.com/shale.
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[1] See 25 Pa. Code §78.55 (as part of the permitting process, drilling companies must disclose the names of all chemicals to be stored and used at a drilling site in the Pollution Prevention and Contingency Plan submitted to the Department of Environmental Protection); Wy. Oil & Gas Comm'n § 3-8(c) (operators must disclose chemical additives and proposed concentrations in the Application for Permit to Drill or Deepen). Ariz. Admin. Code § 12-7-117 (operators of wells using "artificial stimulation" must report the amount and types of material injected within 15 days of the procedure).
[2] HB 3328, 2011 Leg., 82 Sess. (TX 2011). For an in-depth analysis of HB 3328 and the proposed Texas disclosure requirements, see Texas Legislature Joins Growing Number of States in Requiring Disclosure of Hydraulic Fracturing Fluids, Fulbright Briefing (June 16, 2011).
[3] 36 Tex. Reg. 5765 (2011) (to be codified at 16 Tex. Admin. Code § 3.29) (proposed September 9, 2011) (Railroad Commission of Texas).
[4] Supervisor of Wells Instruction 1-2011, High Volume Hydraulic Fracturing Well Completions, State of Michigan Department of Environmental Quality (May 23, 2011).
[5] Keith B. Hall, Michigan Issues New Hydraulic Fracturing Regulations, Oil & Gas Law Brief, Stone Pigman Walther Wittmann L.L.C.
[6] Administrative Rules of Montana, Title 36, Chapter 22.
[7] N.Y. Comp. Codes R. & Regs. tit. 6, Parts 52, 190, 550–556, 560, 750
[8] LAC 43:XIX Subpart 1, Chapter 1.
[9] N.D. Admin. Code § 43-02-03-27.1.
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