The "Brown Dense" -- Another Potential Oil Play

The "Brown Dense" is the latest shale formation to generate excitement as a potential oil play.  The Brown Dense stretches across Southern Arkansas and into several parishes in North Louisiana, including Claiborne, Union, and Morehouse.

In a statement issued earlier today, Louisiana Department of Natural Resources Secretary Scott Angelle stated, "This is yet another opportunity for Louisiana to show that we can be an inviting and exciting province to do the business of finding and providing new sources of domestic energy that provide economic strength and opportunity for our state and nation." 

The Brown Dense is located at vertical depths from 8000 to 11,000 feet, and has a thickness that ranges from 300 to 550 feet.  The formation sometimes is called the Lower Smackover because it is located below the Smackover formation that has been a source of oil and gas production in North Louisiana and South Arkansas since the 1920s.

On July 28, 2011, Southwestern Energy issued an earnings report in which it announced that it has invested $150 million to acquire mineral rights in 460,000 acres to develop the formation.  Southwestern stated that it plans to begin drilling its first Brown Dense well in Columbia County, Arkansas late in the third quarter of 2011.  That well is expected to be drilled to a vertical depth of 8900 feet, with a horizontal lateral of about 3500 feet.  Southwestern plans to drill its second Brown Dense well sometime later in 2011 in Claiborne Parish, Louisiana.  The company expects that the second well will have a vertical depth of 10,700 feet and a 6000-foot horizontal lateral.  Southwestern stated that it could drill as many as 10 additional Brown Dense wells in 2012.

In an August 3, 2011 earnings call, Devon Energy announced that it has acquired minerals rights to 40,000 acres in North Louisiana for purposes of developing the Brown Dense formation, and that it expects to drill its first well to that formation in September 2011.  Devon will drill that well in Morehouse Parish.

Southwestern has a page on its website that provides additional details regarding the company's plans for the Brown Dense, and the terms of its leases. 

Department of Energy Recommendations Regarding Hydraulic Fracturing

A Department of Energy advisory panel recently issued a report regarding shale gas production and hydraulic fracturing.  The report identified benefits of those processes, but also noted various concerns and made several recommendations.  Prior posts in the Oil & Gas Law Brief discussed the benefits and the concerns discussed in the report.  This post discusses the recommendations made by the report, and notes some good news -- regulators and industry already are taking some of the actions recommended in the report.    

1. Recommendations Relating to Water Quality

The report acknowledges that most experts believe that there is relatively little risk that the underground fractures created by the fracturing process will serve as a pathway for contamination of underground sources of drinking water.  A greater concern is the possibility that well construction failures will allow contamination of drinking water aquifers.  To minimize the risk of well construction failures, the report recommends that companies and regulators adopt best practices in well construction techniques, including techniques for the casing and cementing of wells, and for testing the integrity of cementing jobs.  Ohio recently revised its well construction regulations, and other states are examining their existing regulations. 

The report also recommended the use of microseismic surveys to determine the extent of hydraulic fracture growth.  Although few (if any) people who have studied the issue believe that fractures will extend far enough to cause contamination of drinking water aquifers, many companies already are taking steps to monitor the extent of hydraulic fracture growth.

The report recommended that regulators require disclosure of the chemicals used in fracturing water, with protection for the identity of chemicals that qualify as actual trade secrets.  Wyoming, Arkansas, West Virginia, and Texas already have enacted disclosure requirements.  Louisiana regulators have proposed a mandatory disclosure regulation, and will hold a public hearing on the proposal tomorrow.  Montana regulators also have proposed such rules, and Michigan has enacted rules requiring operators to supply Material Safety Data Sheets to state regulators for the substances used in fracking.  Other states, including Colorado and New York are considering such regulations, and the federal government is considering such regulations for oil and gas drilling done on federal lands.  In addition, many companies have started voluntarily disclosing the composition of fracking fluid on the website FracFocus or on their own company websites.

The report recommended additional field studies to examine the possibility of methane leakage from shale gas wells to water reservoirs, and the adoption of a requirement for background testing of water wells prior to drilling of gas wells in an area.  Such field studies are part of the EPA's ongoing study of hydraulic fracturing.  Further, Pennsylvania has moved to require background testing of water wells prior to drilling of gas wells, and other states are considering such measures.

The report recommended eliminating the use of diesel as an additive to hydraulic fracturing fluid.  The EPA is moving to regulate (though not prohibit) such use. 

The report recommended the development of "green" drilling and fracturing fluids.  Some companies already have introduced "green" fracking additives that are drawn from substances that qualify as food additives.

2. Recommendations Relating to Air Quality

In order to promote improved air quality, the report recommended that companies and regulators implement efforts to reduce emissions of methane during drilling of wells, and subsequent production, post‑production treatment, and transport of natural gas.  So far, water issues have received the most attention from regulators, but the Department of Energy report noted that some states already have implemented regulations to reduce air emissions and that the United States EPA also recently proposed regulations to reduce air emissions. 

In addition to the measures noted above, the report recommended that companies make efforts to better measure emissions and that studies be made to estimate life cycle emissions for production, transport, and use of natural gas.

The report recommended reducing the use of diesel engines to power pumps and other equipment at drilling sites, and that natural gas engines or electric motors be used instead.

3. Other Recommendations

To minimize surface disturbances, the report recommends the use of multi‑well drill pads.  The report recommended efforts to mitigate noise, air and visual pollution, and traffic and congestion issues in the vicinity of drilling locations.  Some states, including Louisiana, already have enacted regulations to mitigate local disturbances.

The report recommended the sharing of technology by regulators and industry through the use of technology peer reviews and the creation of a shale gas industry group to develop best practices and standards.

The report recommended the creation of a national database that would link various existing sources of public information to make the information more easily accessible to the public. 

U.S. State Deparment Issues Study of Proposed Keystone XL Pipeline

Earlier today, the United States Department of State issued its final Environmental Impact Statement (EIS) regarding the proposed Keystone XL pipeline, which would run from Alberta, Canada to the Texas Gulf Coast.  Because the pipeline would cross the border, the State Department must give its approval for the project.  Issuance of EIS does not constitute approval of the project, but it does put the proposed project one step closer to potential approval bcause an EIS is required by the National Environmental Policy Act before the project can be approved.

The principal purpose of the proposed 1711-mile long, 36-inch diameter pipeline would be to transport oil from Alberta, Canada to refineries on the U.S. Gulf Coast.  Production of heavy crude from oil sands (also called tar sands) found in Alberta is increasing rapidly at the same time that refineries in parts of the U.S. need alternative supplies of of heavy crude.  Although it is anticipated that the pipeline, if constructed, would mainly transport oil from Alberta, it also could transport oil produced in the northern U.S., included oil from the Bakken Shale in Montana and North Dakota, and oil from near Cushing, Oklahoma.  Oil could be delivered to Cushing, as well as to Nederland, Texas and Moore Junction, Texas.

Critics of the proposal voice concerns about the possibility of spills and about the footprint of the pipeline itself.  Also, many environmentalists oppose expanded production of oil from oil sands, arguing that too much energy is used in producing such oil, that too much water is used in the production process, and that production from oil sands causes too much surface disturbance (usually a process similar to strip mining is used in the production of oil from oil sands, though companies are required to restore the surface).  See the May 2, 2011 post of the Oil & Gas Law Brief for a discussion of oil sands.

Supporters argue that oil sands provide a bountiful supply of petroleum from a nearby, stable, friendly country, and that most "easy" sources of oil already have been developed.

The Summary of Findings section of the full EIS states that "most resources would not experience significant impacts" from the proposed pipeline.  The same section states that there would be "adverse effects to certain cultural resources along the proposed Project corridor," but that "mitigation measures have been developed ... to address these adverse impacts."  The Summary of Findings also states that there would be adverse effect to the American burying beetle, raising Endangered Species Act issues, but that Keystone has offered to provide money to acquire habitat area for the beetle, and that Keystone and various government agencies have discussed conservation measures that could minimize potential impacts to the American burying beetle.

The Department of State issued an announcement of its release of the Environmental Impact Statement, and provided a web page where readers can find a "fact sheet" regarding the EIS, an Executive Summary of the EIS, a listing of upcoming public meetings on the subject, and a copy of the full EIS, as well as other documents relating to the proposed project.  The fact sheet includes a map of the proposed route for the pipeline.

New Jersey Governor Chris Christie Vetoes Ban on Hydraulic Fracturing

Yesterday, New Jersey Governor Chris Christie conditionally vetoed a bill that would have made his state the first to ban hydraulic fracturing.  As reported in the Oil and Gas Law Brief on July 3, the New Jersey legislature passed the bill by wide margins in both the House and Senate.  In his veto message, Governor Christie recommended that the bill be revised to replace the proposed ban with a one-year moratorium on hydraulic fracturing.  

While I do share the sponsors' concerns about protecting our drinking water, I do not believe that the case has been made to justify a complete, permanent, statutory prohibition on fracking.  The legislative process revealed a substantial disagreement between those who favored a ban on fracking and those who opposed it.  Significantly, the bill was pushed through the legislature at the very same time that two federal agencies -- the Environmental Protection Agency (USEPA) and the Department of Energy (USDOE) -- were studying the environmental impact of this drilling technique."

Governor Christie stated that, "We must ensure that our environment is protected and our drinking water is safe."  But he also noted that shale gas production has substantial economic benefits.  Further, because gas is the cleanest burning of all fossil fuels, there are environmental benefits whenever shale gas is produced and used in place of coal.

In addition, I believe it would be premature and ill-advised to impose a permanent ban while the USDOE and USEPA are studying this issue and without the benefit of the views of the New Jersey Department of Environmental Protection (NJDEP).  Accordingly, based on all of these circumstances, I believe that the better approach to this issue is to impose a one-year moratorium on fracking in  New Jersey while the USDOE and USEPA continue to study fracking, and the NJDEP conducts an independent evaluation of the issue and reports its findings."

Governor Christie's veto message expressly acknowledged that some people have raised concerns that improperly cased gas wells could allow underground sources of drinking water to become contaminated, and he stated he has no doubts about the "good intentions of those who support this legislation, [but] I do not believe that the scientific grounds needed to justify an outright, permanent, statutory ban were established during the legislative process." 

A small portion of the Utica Shale, which is beneath the Marcellus Shale, extends into New Jersey, but there has not been any Utica Shale development in the state and no company has announced plans to drill there.

Governor Christie made his recommendation to amend the bill to impose a moratorium, rather than a permanent ban, in accordance with Article V, Section I, paragraph 14 of the New Jersey Constitution.  That provision states that a governor who chooses to veto a bill may veto the bill outright, or veto the bill with recommendations of changes to the bill that would make the bill acceptable to the governor.  The legislature may override a conditional veto by a two-thirds vote in order to enact the bill into law in its original form, or the legislature may enact the govenor's recommended changes by majority vote.  If the legislature does neither, the conditionally vetoed bill dies and does not become law.  

Responses to the veto have been mixed.  An industry publication, the Oil and Gas Journal, has reported that some supporters of shale gas development have expressed disappointment that Governor Christie did not veto the ban outright, while others were pleased with Governor Christie's attempt to replace the ban with a one-year moratorium.  Environmental groups have called for the legislature to override the conditional veto.

West Virginia DEP Announces Regulations for Hydraulic Fracturing

The West Virginia Department of Environmental Protection has announced issuance of regulations to govern hydraulic fracturing.  Among other things, the regulations will require that operators:

  • provide WVDEP with estimates of the amount of water they will use in drilling and fracturing their wells
  • develop and submit to WVDEP water management plans for any wells that they estimate will use more than 210,000 gallons of water during any one-month period
  • include in their water management plans information identifying the type of water source, such as surface or ground water, the specific location from which they anticipate withdrawing such water, the anticipated volume to be withdrawn, and when they anticipate withdrawing the water
  • identify all existing water uses within one mile downstream of a location where they will withdraw surface water, and ensure that enough in-stream flow remains to protect identified downstream uses
  • include in their water management plans the additives they anticipate using in their fracturing water, and (after completion of the well) provide a listing of the actual additives used 
  • record the quantity of flowback water, the quantity of produced water, and the method of management or disposal of the flowback and produced water
  • dispose of all drilling cuttings and drilling mud generated from wells that disturb more than three acres of surface or use more than 210,000 gallons of water during any one-month period at an approved solid waste facility, or manage such cuttings and drilling mud on-site in a manner approved by WVDEP
  • construct their wells in conformance with casing standards and cementing standards published by the American Petroleum Institute
  • develop erosion and sediment control plans for any well site that will disturb three or more acres of surface, and
  • publish a public notice at least 30 days in advance of the issuance of a permit to drill the first well from any particular well pad that is located within the boundaries of any municipality.

Governor Earl Ray Tomblin requested that WVDEP prepare hydraulic fracturing regulations in his Executive Order 4-11 on July 12, 2011 (as reported in this blog on July 19).  The regulations were promulgated under WVDEP's emergency powers, which allowed for the regulations to be developed and put into effect more quickly than under the standard rule-making process.  Governor Tomblin's Executive Order indicates that the regulations are intended to govern hydraulic fracturing in West Virginia pending further action from the state legislature.

Hydraulic Fracturing Litigation: Nuisance and Breach of Contract Claims

More and more plaintiffs are filing lawsuits in which they claim that their drinking water has been contaminated by hydraulic fracturing operations.  The Oil and Gas Law Brief began a series of posts discussing this topic about a month ago.  Prior posts have provided an introduction to hydraulic fracturing litigation (July 18) and discussed claims based on an abnormally dangerous activity legal theory (July 25), defenses to claims based on an abnormally dangerous activity theory (July 29), and claims based on subsurface trespass (August 1). 

1.                  Nuisance

"A private nuisance is a nontrespassory invasion of another's interest in the private use and enjoyment of land."  See Restatement (Second) Torts § 821(D). The pollution of surface or ground waters can constitute a private nuisance.  See id. at § 832  For a defendant to have liability for a private nuisance, his invasion of the plaintiff's interest must be either (a) "intentional and unreasonable," or (b) actionable under rules controlling liability for negligence or abnormally dangerous activity.  See id. at § 822.  An invasion of the plaintiff's interest is considered intentional if the defendant acts for the purpose of causing the invasion of interest, or he knows that his actions are causing the invasion, or he knows that his actions are substantially certain to do so.  See id. at § 823 

To defeat a nuisance claim, a defendant should concentrate on demonstrating that it did not intend the alleged invasion and did not know that the alleged invasion was substantially certain to occur.  The defendant should also argue that its conduct was not unreasonable.  If a defendant conducted its activity in compliance with a permit issued by regulators, the defendant should point to that as evidence of its reasonableness.  The defendant also can point to the value that hydraulic fracturing provides to the community -- jobs, tax revenue, a decreased dependence on foreign sources of energy, and the production of a clean burning fuel. 

To the extent the plaintiff argues that the defendant is liable for private nuisance because the defendant's conduct would be actionable under theories of nuisance or strict liability for an abnormally dangerous activity, a defendant would defend against such a nuisance claim in the same way that he would defend against claims brought under negligence or strict liability theories.

2.                  Breach of contract

Oil and gas well operators typically operate pursuant to a mineral lease with the person holding mineral rights to the land on which the well is drilled (the mineral rights owner may or may not be the landowner).  In addition to the mineral lease, the oil and gas company may have a surface use agreement with the landowner.  These contracts may contain clauses which would give the landowner a basis to bring suit in the event his land or groundwater beneath his land were contaminated.  In addition, courts typically impose upon mineral lessees various implied covenants that require lessees to conduct their activities as reasonably prudent operators.  This standard of conduct sounds very much like a negligence standard, and a landowner could assert a claim based on an argument that a lessee breached an implied covenant to act as a reasonably prudent operator by causing contamination of the landowner's property or the groundwater beneath it. 

If a plaintiff alleges that the defendant breached an implied covenant by negligently allowing fracturing to cause contamination, the defendant should argue that the plaintiff's claim sounds only in tort.  A few decisions have held that a plaintiff may assert an implied covenant claim based on the defendant allegedly causing or allowing an accident.  See, e.g., Empire Oil & Refining Co. v. Hoyt, 112 F.2d 356 (6th Cir. 1940).  But there are not many such cases.  Generally, implied covenants are used to ensure that lessees are diligently exploring for and producing minerals.  See generally Keith B. Hall, The Continuing Role of Implied Covenants in Developing Leased Lands, 49 Washburn L.J. 313 (2010). 

Implied covenants are imposed by courts in the context of oil and gas leases more frequently than in the context of other types of contracts because of a particular characteristic of oil and gas leases.  Namely, because of the uncertainties involved in mineral exploration, oil and gas leases generally do not specify in detail the exploration and production activities the lessee will conduct.  See Keith B. Hall, Implied Covenants:  Claims Under Article 122, 57 Min. L. Inst. 172, 173-4 (2010).  Thus, some of the most important aspects of a lessee's performance are left to his discretion.

Because so much is left to the discretion of the lessee, courts impose implied covenants to protect the lessor by requiring the lessee to be reasonably diligent in exploration and development.  See id.; see also Patrick H. Martin, A Modern Look at Implied Covenants to Explore, Develop, and Market Under Mineral Leases, 27 Sw. Legal Fdn. Oil & Gas Inst. 177, 194 (1976).  But implied covenants are not needed to guard against negligent conduct because negligence law already does that.  Accordingly, if the factual basis of a lessor's claim is the alleged negligence of the lessee, the lessee can argue that such a claim sounds in tort and that it does not constitute a breach of contract claim. 

A future post will discuss the types of expert witnesses the parties may need in hydraulic fracturing litigation.

Carnegie Mellon Study on Life Cycle Greenhouse Gas Emissions for Shale Gas Reaches Different Conclusions than Cornell Study

A group of researchers from Carnegie Mellon have released a study that estimates the "life cycle" greenhouse gas emissions for Marcellus shale gas.  The "life cycle estimates" are estimates of the total amount of greenhouse gas emissions for all activities associated with the production, treatment, transport, and ultimate use of shale gas for electricity production.  The researchers compared their life cycle estimates for Marcellus shale gas to similar estimates for coal and for natural gas produced by conventional means.  In contrast to the conclusions reached by a Cornell study, the Carnegie Mellon researchers concluded that Marcellus shale gas has life cycle greenhouse gas emissions that generally are significantly lower than the life cycle emissions for coal, and that are only slightly higher than those for natural gas produced from conventional wells that are not hydraulically fractured.

The Carnegie Mellon researchers estimated emissions for three greenhouse gases -- carbon dioxide, methane, and nitrous oxide -- and converted those emissions to "carbon dioxide equivalents" using the 100-year global warming potential (GWP) factors reported by the Intergovernmental Panel on Climate Change (IPCC).  The conversion is made because each type of greenhouse gas has a different amount of global warming potential.  For example, a molecule a methane is estimated to have 25 times more global warming effect than a molecule of carbon dioxide.  Thus, a molecule of carbon dioxide would count for one carbon dioxide equivalent, while a molecule of methane would count for 25 carbon dioxide equivalents. 

The "100-year" reference refers to the fact that the global warming effect is based on the global warming effect that emissions will have after 100 years have passed.  A specific time horizon must be chosen because methane will breakdown in the atmosphere over time, thereby decreasing its greenhouse gas effect over time.  Thus, the immediate greenhouse gas potential is different than that which will remain after 20 years, which is different than that which will remain after 100 years.  The 100-year greenhouse gas potential is used to obtain long range estimates of the greenhouse gas effect of emissions.  

The Carnegie Mellon researchers attempted to be comprehensive in the activities they chose to include in their life cycle analysis.  They included estimated emissions for various parts of the pre-drilling and pre-production process, including emissions from the operation of equipment used in constructing the well pad, equipment used in the drilling process, motors used in pumping fracturing fluid into the well for the fracking process itself, and trucks used is delivering water to the drill site for fracturing, as well as emissions associated with producing drilling mud, emissions from the process of venting or flaring during flowback and well completion, fugitive emissions that occur during treatment and transport of shale gas, and emissions from combustion when the gas ultimately is used to generate electricity in a power plant. 

The Carnegie Mellon researchers concluded that the life cycle greenhouse gas emissions for Marcellus shale gas emissions are about 3% higher than for natural gas produced from conventional wells, and are about 3% lower than liquefied natural gas imported to the U.S.  They estimated that the life cycle emissions for the use of Marcellus shale gas in power generation are much lower than for the use of domestic coal is most scenarios.  The one exception is a scenario in which one assumes that a power plant uses advanced carbon capture and sequestration (CCS) technology.  If CCS is used for both a natural gas-fired power plant and a coal-fired power plant, the estimated life cycle emissions for coal are slightly lower than for Marcellus shale gas.

The Carnegie Mellon researchers did not assume that so-called "green" completions or "reduced emissions" completions would be used during flowback and completion of a Marcellus well.  Such techniques would reduce emissions.  A couple of western states now require green completions, and some companies voluntarily are using green completions.  Further, the EPA has proposed regulations that would require green completions starting in March 2012.  If the Carnegie Mellon researchers had assumed that green completions are used, their estimates of life cycle greenhouse gas emissions for Marcellus shale gas would be closer to the life cycle estimates for natural gas produced from conventional wells, and would compare even more favorably relative to coal than when it is assumed that green completions are not used.

The Carnegie Mellon researchers' results contrast with those of a study by Cornell researchers, who concluded that shale gas has higher life cycle greenhouse gas emissions than those for the use of coal, whether one looks at a 20-year time horizon or a 100-year time horizon.

The Carnegie Mellon study was funded in part by the Sierra Club.

Hydraulic Fracturing: Concerns Expressed in Department of Energy Report

A United States Department of Energy advisory panel recently issued a report on issues relating to shale gas production, including the use of hydraulic fracturing.  That report of the Shale Gas Subcommittee of the Secretary of Energy Advisory Board identified several benefits of shale gas production and hydraulic fracturing, but also discussed several concerns relating to shale gas production, and made recommendations to address those concerns.  This blog's August 15 post discussed the benefits identified in the report.  As to concerns, the report stated:

The Subcommittee identifies four major areas of concern:  (1) Possible pollution of drinking water from methane and chemicals used in fracturing fluids; (2) Air pollution; (3) Community disruption during shale gas production; and (4) Cumulative adverse impacts that intensive shale production can have on communities and ecosystems."

(1) Possible Pollution of Drinking Water

The Subcommittee concluded that one of the most common worries about hydraulic fracturing relates to a type of event that is unlikely to occur.  The Subcommittee explained:  "One of the commonly perceived risks from hydraulic fracturing is the possibility of leakage of fracturing fluid through fractures into drinking water.  Regulators and geophysical experts agree that the likelihood of properly injected fracturing fluid reaching drinking water through fractures is remote when there it is a large depth separation between drinking water sources and the producing zone.  In the great majority of regions where shale gas is being produced, such separation exists and there are a few, if any, documented examples of such migration." 

The Subcommittee shares the prevailing view that the risk of fracturing fluid leakage into the drinking water sources through fractures made in deep shale reservoirs is remote." 

The report stated that if a water well becomes contaminated, it is less likely to be contaminated with fracturing fluid than with methane, the principal component of shale gas ("shale gas" is sometimes used in referring to natural gas produced from shale).  The report concluded that, "Methane leakage from producing wells into surrounding drinking water wells, exploratory wells, production wells, abandoned wells, underground mines, and natural migration is a greater source of concern."  

The report stated, though, that if a water well is contaminated with methane, the contamination is not necessarily the result of fracturing.  "The presence of methane in wells surrounding a shale gas production site is not ipso facto evidence of methane leakage from the fractured producing well since methane may be present in surrounding shallow methane deposits or the result of past conventional drilling activity." 

And, if a hydraulically fractured well is the cause of contamination, the pathway for flow of contaminants is less likely to be fractures created in shale during the fracturing process than it is to be a pathway that results from a well construction failure -- specifically, a poor casing or cementing job.  In fact, noted the report, a poorly cased and cemented well could potentially leak "regardless of whether the well has been hydraulically fractured."  

The report stated that surface spills also potentially could cause contamination of shallow drinking water formations.  But the potential for contamination from surface spills is a hazard that is not unique to the fracturing process, or to the oil and gas industry.  Our society uses a number of hazardous chemicals in a variety of industries. 

(2) Air Pollution

The Subcommittee noted two air pollution concerns.  One relates to emissions from the use of diesel engines for various purposes, including running pumps, at the fracturing site.  The report suggested that gasoline engines or electric motors could be substituted for diesel engines.  A second air pollution concern is leakage or emissions of methane during drilling and during the subsequent production, processing, and transport of natural gas.  The report explained that methane emissions are a concern because methane is a more potent greenhouse gas than carbon dioxide.  Regulators and industry already are addressing this concern, as will be discussed in more detail in a future post by this blog discussing the report's recommendations.

(3) Community disruptions and (4) Cumulative Impacts

The report expressed concern about traffic congestion and other issues that can arise from actions that are not disruptive or problematic individually, but which cumulatively can have a disruptive effect when such actions are repeated many times.

Other Concerns Identified in Report

In addition to the four main concerns discussed by the report, the report noted that water supply issues sometimes can be a problem.  The report notes that hydraulic fracturing of a typical shale gas well requires between 1 and 5 million gallons of water.  The report states that, "While water availability varies across the country, in most regions water used in hydraulic fracturing represents a small fraction of total water consumption.  Nonetheless, in some regions and localities there are significant concerns about consumptive water use for shale gas development."

The report noted that proper disposal of flowback water also sometimes is an issue.  The report noted that one way to deal with flowback is to recycle it for use as part of the fracturing fluid in future frack jobs.  This reduces the amount of flowback that requires disposal, and reduces the amount of new water which must be supplied.  Companies are using such recycling on a more frequent  basis.

Report's Observation about the Public Debate

The Subcommittee's report also made observations about the seemingly conflicting claims of proponents and opponents of hydraulic fracturing.  The report notes that supporters of hydraulic fracturing state that it has been performed safely without significant incident for over 60 years, and the report acknowledges that the supporters of fracking have a point. 

Opponents point to failures and accidents and other environmental impacts, but these incidents are typically unrelated to hydraulic fracturing per se and sometimes lack supporting data about the relationship of shale gas development to incidence and consequences." 

But the report suggested that supporters' references to the lack of documented problems caused by fracking will not win the public relations battle, and that some opponents do point to real problems, even if the problems generally do not arise from the fracking process itself.  The report observed that proponents and opponents look at a different scope of activities in judging hydraulic fracturing.   

The report states:  "Some of this difference in perception can be attributed to communication issues.  Many in the concerned public use the word 'fracking' to describe all activities associated with shale gas development, rather than just the hydraulic fracturing process itself.  Public concerns extend to accidents and failures associated with poor well construction and operation, surface spills, leaks at pits and empowerments, truck traffic, and the cumulative impacts of air pollution, land disturbance and community disruption." 

The Subcommittee stated that some of its observations perhaps could be extended to other types of oil and gas operations, but that the Subcommittee intended to focus on shale gas development and that the Subcommittee "caution[s] against applying our findings to other areas, because the Subcommittee has not considered the different development practices and other types of geology, technology, regulation and industry practice."

In a subsequent post, this blog will discuss the report's recommendations, some of which are steps that regulators already are being taken by regulators. 

West Virginia Court Strikes Down a City's Ban on Hydraulic Fracturing

A state court judge in West Virginia has struck down an ordinance enacted by the City of Morgantown to ban hydraulic fracturing within the City and anywhere within one mile of the City.  The case was filed by Northeast Natural Energy, LLC, which previously had received a permit from the West Virginia Department of Environmental Protection to drill and hydraulically fracture a Marcellus Shale well in an area outside the city limits of Morgantown, but within one mile of the City.  Northeast had not yet hydraulically fractured the well when the ordinance went into effect.  Northeast argued to the court that the City's ordinance was preempted by state law and therefore was unenforceable. 

The case was assigned to Judge Susan Tucker, who granted summary judgment in favor of Northeast on August 12, 2011.  Her opinion discussed the concept of preemption, explaining that when state legislation "fully occupies" a particular subject area, establishing a "comprehensive regulatory scheme," no local ordinance can contravene that state law.  To determine whether state law would preempt local laws regulating hydraulic fracturing, Judge Tucker examined state statutes relating to environmental protection and regulation of the oil and gas industry.

Judge Tucker noted that West Virginia statutes declare that "The state has the primary responsibility for protecting the environment; other government entities, public and private organizations and our citizens have the primary responsibility of supporting the state in its role as protector of the environment."  Another statute declares that the purpose of the West Virginia Department of Environmental Protection ("WVDEP") is to "consolidate environmental regulatory programs in a single agency, while also providing a comprehensive program for the conservation, protection, exploration, development, enjoyment and use of the natural resources of the state of West Virginia."  State law also requires the Director of the WVDEP to maintain an office of oil and gas under his supervision, with that office being charged with a duty of administering and enforcing the West Virginia Oil and Gas Act.  In addition, a state statute indicates that it is within the sole discretion of the WVDEP to perform all duties relating to the exploration, development, production, storage, and recovery of West Virginia's oil and gas.

Judge Tucker determined that these statutes demonstrate that West Virginia has enacted a comprehensive state regulatory program that will preempt any local ordinance that is inconsistent with state law, rendering such local ordinances invalid.  In this case, the local ordinance enacted by Morgantown was inconsistent with state law because the local ordinance would ban certain drilling and hydraulic fracturing altogether, even if the processes are authorized by WVDEP.  Therefore, the ordinance was invalid.  The case is Northeast Natural Energy, LLC v. City of Morgantown, Civil Action No. 11-C-411, Circuit Court of Monangalia County.

Similar issues can arise in other states, many of which have statutes that attempt to make a state regulatory agency the sole (or at least the primary) body that regulates the oil and gas industry.  For example, Louisiana law requires a person to obtain a permit from the Office of Conservation before drilling a well, and provides that Conservation's grant of a permit will constitute "sufficient" authority to drill.  Another state statute expressly states that "[n]o other agency or political subdivision of the state shall have the authority, and they are hereby expressly forbidden, to prohibit or in any way interfere with the drilling of a well or test well in search of minerals by the holder of such a permit."  In 2006, the United States Fifth Circuit held that the ordinance completely preempted and therefore rendered unenforceable a Shreveport ordinance that attempted to bar drilling within 1000 feet of a lake that served as the source of drinking water, and to regulate drilling that occurred further away.  See Energy Management Corp. v. Shreveport, 397 F.3d 297 (5th Cir. 2006).

The extent to which local governments may prohibit or regulate oil and gas drilling will differ from one state to another, but in many states the authority of local governments is significantly restricted in this subject area by state laws such as those in West Virginia and Louisiana, which attempt to establish a comprehensive regulatory program for oil and gas that is overseen by a single state agency.

Department of Energy Panel Confirms Benefits of Hydraulic Fracturing and Shale Gas Production, But Recommends Changes

Late last week, a United States Department of Energy advisory panel announced the release of its initial report on shale gas development and hydraulic fracturing.  The report discussed benefits of shale gas production, as well as concerns about such production, and made several recommendations.

The panel identified the same three types of benefits previously discussed in this blog -- (1) economic benefits, (2) national security benefits, and (3) environmental benefits.

The economic significance is potentially very large.  While estimates vary, well overt [sic] 200,000 jobs (direct, indirect, and inducted) have been created over the last several years by the development of domestic production of shale gas, and tens of thousands more will be created in the future."

Further, the report notes that increased supplies have contributed to reductions of more than 50% in the price of natural gas "since 2008, benefiting consumers in the lower cost of home heating and electricity."

The panel concluded that shale gas production will reduce the country's dependence on imported natural gas, and perhaps even imported oil, thereby providing important national security benefits. 

As late as 2007, before the impact of the shale gas revolution, it was assumed that the United States would be importing large amounts of liquefied natural gas from the Middle East and other areas.  Today, the United States is essentially self-sufficient in natural gas, with the only notable imports being from Canada, and is expected to remain so for many decades."

Further, "Domestic production of shale gas also has the potential over time to reduce dependence on imported oil for the United States."  This would be beneficial because a significant portion of imports come from politically unstable areas, including areas sometimes hostile to the United States.  A similar benefit applies as to the country's foreign allies: "International shale gas production will increase the diversity of supply for other nations.  Both these developments offer important national security benefits."

Finally, the report noted that shale gas production has potential environmental benefits because natural gas is the cleanest burning of all fossil fuels.  The report stated that shale gas "offers climate change advantage because of its low carbon content compared to coal."

The report, dated August 11, 2011, was issued by the Shale Gas Subcommittee of the Secretary of Energy Advisory Board.  In later posts, this blog will discuss the concerns raised in the report, as well as the recommendations contained in it.

Will EPA's Proposed Air Rules for Fracking Make the Cornell Study Moot?

Proponents of hydraulic fracturing argue that fracking has several benefits (see my April 1, 2011 post), including an environmental benefit.  The environmental benefit is that fracking often is used to produce natural gas, the cleanest burning of all fossil fuels.  On an energy equivalent basis, the combustion of natural gas produces only half as much carbon dioxide as does coal, and it also produces less particulate matter, sulfur dioxide, and nitrous oxides.  Thus, to the extent that the use of natural gas displaces the use of coal, hydraulic fracturing can be good for air quality and for the effort to curb climate change.  

But earlier this year, a study released by Cornell researchers challenged the notion that the use of natural gas produced from shale will result in lower emissions of greenhouse gases.  The study concedes that natural gas is clean burning, but concludes that the production of natural gas from shale results in large releases of methane during the fracturing process, and in particular during the recovery of flowback water.  Methane is the principal component of natural gas and, like carbon dioxide, is a greenhouse gas.  In fact, methane has a stronger greenhouse gas effect than carbon dioxide (though, in the long run, the methane will break down in the atmosphere).

The Cornell study was based on the assumption that natural gas that accompanies flowback would be vented to the atmosphere, not recovered or flared.  Critics of the Cornell study questioned that assumption, and now the EPA has proposed new air rules (see my post on this subject) that generally will require recovery of natural gas that accompanies flowback.  

In certain circumstances in which recovery is not practical, the proposed new rules would require flaring, rather than venting.  In flaring, the natural gas that otherwise would be vented is burned.  The flaring results in emissions of carbon dioxide, but the greenhouse gas effect of that carbon dioxide is less than that of the natural gas that would be vented if it were not flared.  Thus, flaring generally is preferable to venting. 

The proposed new rules may moot the concerns raised by the Cornell study and convince more people that hydraulic fracturing can have environmental benefits.

EPA Proposes New Air Rules for Hydraulic Fracturing and for the Oil and Gas Industry

On July 28, 2011, the EPA announced a proposal for four new regulations and a new source performance standard to reduce the emissions of methane and volatile organic compounds ("VOC") from the oil and gas industry.  One of the new regulations specifically addresses hydraulic fracturing.  The EPA's proposals address five types of sources.  The EPA released a "Fact Sheet" and a slide presentation that included the following information.

Hydraulic fracturing                                           

  • Companies would be required to minimize VOC emissions by using "green completions," also called "reduced emissions completions," in which equipment is used to separate gas and liquid hydrocarbons from the flowback water that comes from the well after hydraulic fracturing.
  • After separation from flowback, the gas and hydrocarbons can then be recovered, treated, and sold.
  • Some states, such as Wyoming and Colorado, require "green completions," and a number of companies are voluntarily using this process through EPA's Natural Gas STAR program. 
  • EPA estimates that use of "green completions" after hydraulic fracturing will reduce VOC emissions from completions and recompletions of hydraulically fractured wells by 95 percent.
  • When gas cannot be collected, VOCs would be reduced through pit flaring, unless it is a safety hazard.
  • Methane, a potent greenhouse gas, also would be significantly reduced as a co‑benefit of reducing VOCs.
  • The green completion requirements would not apply to exploratory wells or delineation wells (used to define the borders of a natural gas reservoir), because they are not near gas sales lines.  Those wells must use pit flaring to burn off their emissions, unless it is a safety hazard.


  • Compression is necessary to move natural gas along a pipeline.  Centrifugal compressors would have to be equipped with dry seal systems in order to reduce VOC emissions.
  • Owners/operators of reciprocating compressors would have to replace rod packing systems after every 26,000 hours of operation.

Pneumatic controllers

Pneumatic controllers are automated instruments used for maintaining a condition such as liquid level, pressure, and temperature at wells, gas processing plants, compressor stations, among other locations.  These controllers may release natural gas (including VOCs and methane) with every valve movement, or continuously in some cases.

EPA is proposing VOC emission limits for pneumatic controllers. 

  • For new or replaced pneumatic controllers at gas processing plants, the proposed limits would eliminate VOC emissions.  These limits could be met through using controllers that are not gas‑driven.
  • For controllers used at other sites, such as compressor stations, the emission limits could be met by using controllers that emit no more than six cubic feet of gas per hour.
  • The proposed amendments include exceptions for controllers in applications requiring high‑bleed controllers for certain purposes, including operational requirements and safety.

Condensate and crude oil storage tanks

  • Tanks with a throughput of at least 1 barrel per day of condensate or 20 barrels per day of crude oil must reduce VOC emissions by 95 percent.

Natural gas processing plants

  • EPA is proposing to amend the existing new source performance standards ("NSPS") for natural gas processing plants to strengthen the leak detection and repair requirements that apply to these plants to reduce VOC emissions.

Benefits and Costs Anticipated by the EPA

EPA estimates the following combined annual emission reductions when the proposed amendments are fully implemented:

  • VOCs:  540,000 tons, an industry‑wide reduction of 25 percent
  • Methane ─ 3.4 million tons, which is equal to 65 million metric tons of carbon dioxide equivalent (CO2e), a reduction of about 26 percent.
  • Air Toxics ─ 38,000 tons, a reduction of nearly 30 percent.

EPA estimates that compliance with the proposed rules will yield a net savings to the industry as a whole.  EPA estimates complying with all of the proposed requirements would cost industry an additional $754 million in 2015.  But compliance will avoid the loss (through venting or flaring) of natural gas and condensate with an estimated value of $783 million, making those products available for sale so that industry sees a net savings of $29 million, though the estimated costs and savings would not be distributed uniformly.

The Litigation that led to the Proposed Rules

In January 2009, WildEarth Guardians and the San Juan Citizens Alliance sued EPA, alleging that the Agency had failed to review the new source performance standards and air toxic standards for the oil and natural gas industry.  In February 2010, the U.S. Court of Appeals for the D.C. Circuit entered a consent decree that requires EPA to sign proposals related to the review of these standards.  EPA must issue final standards by February 28, 2012.


The EPA is accepting comments on the proposed rules 

Study Discusses Effect of Shale Gas on U.S. National Security

The James A. Baker III Institute for Public Policy at Rice University has released a study titled "Shale Gas and U.S. National Security."  The study, dated July 2011, concludes that shale gas -- natural gas produced from shale formations -- will have significant, beneficial impacts on the U.S. economy and national security. 

The study notes that shale gas production has reduced the United States' requirements for imported liquefied natural gas (LNG), thereby freeing up additional supply for Europe.  The study states that already this "has played a key role in weakening Russia's ability to wield an 'energy weapon' over its European customers by increasing alternative supplies to Europe in the form of LNG displaced from the U.S. market."

The dramatic lessening of Europe's dependence on Russian gas will likely reduce Russia's ability to unduly influence political outcomes.  European buyers will have ample alternatives to Russian supplies, thereby reducing Moscow's leverage on the balance of power between Russia and the EU."

The study suggests that the unwillingness of some European countries to condemn Russia's invasion of Georgia, and Germany's opposition to putting the Ukraine on a path toward NATO membership may be influenced by the current dependence of Europe on Russian gas, but that such dependence will diminish in the future, making it easier for the U.S. to gain European support for international policies that are opposed by Russia.

The study concludes that shale gas will also help reduce the influence of other nations that sometimes have been a problem for U.S. foreign policy: "Specifically, shale gas will play a critical role in diminishing the petro-power of major natural gas producers in the Middle East, Russia, and Venezuela and will be a major factor limiting global dependence on natural gas supplies from the same unstable regions that are currently uncertain sources of the global supply of oil."

One of the nations discussed in the report is Iran.  International sanctions have hampered Iran's ability to build significant natural gas export capabilities, and shale gas production in the U.S. will increase global supplies of natural gas, further delaying Iran's ability to develop export capabilities.

Rising U.S. shale gas supplies will also assist the United States in its policies toward Iran.  Given global market economics under a full development of shale scenario, the commercial window for Iran to export large amounts of natural gas is likely to be closed for an additional 20 years, making it easier for the United States to achieve buy-in for continued economic sanctions against Iran.  Shale gas development lowers the chances that Iran can use its energy resources to drive a wedge in the international coalition against it."

The report concludes that delaying the world's need for Iranian gas also increases the chance that political change will take place in Iran before the country can gain influence and support its nuclear ambitions by becoming a major supplier of natural gas to other countries.  Further, it lessens the likelihood that Iran can develop an Iran-to-India pipeline, which, if completed, would be a source of tension between the U.S. and India.

The report concludes that China will have to increase its imports of natural gas significantly in future years as its demand grows, but that increased production of shale gas in the U.S. will lessen China's dependence on natural gas from the Middle East.  And, by also reducing the dependence of the U.S. on sources of natural gas from the Middle East, the increased production of shale gas will decrease the incentive for geopolitical competition between the U.S. and China. 

The report concludes that China will need to import more gas from Russia even with the development of shale gas in the U.S., which will lead to the strengthening of ties between  China and Russia.  But, by implication, the report suggests that the need for China to import gas from Russia will be less with the production of shale gas in the United States than without such production.

The Baker Institute study was supported by the United States Department of Energy. 

Shale Plays Affect Pipeline Economics

The development of shale plays is having significant effects on pipeline use and availability.  The latest example is an announcement by Shell Pipeline that it is considering reversing the direction of flow in its Houma-to-Houston pipeline, which sometimes is called the "Ho-Ho."  The pipeline currently is used to transport product from east to west, but Shell is considering reversing that in order to service the increased supply of oil from such shale plays as the Eagle Ford and Bakken.  If the switch is made, Shell anticipates that the new service, which would be subject to regulatory approval, would begin in early 2013 and could transport approximately 300,000 barrels of crude per day.

Chesapeake Claims Utica Contains Tremendous Amounts of Oil

Chespeake has announced that the portion of the Utica Shale located beneath Eastern Ohio contains large quantities of oil and natural gas liquids.  In an interview with Jim Cramer on "Mad Money," Chesapeake's Aubrey McClendon compared the Utica Shale to Eagle Ford, but said that the Utica Shale might be even better.

The Utica Shale, which is found below the Marcellus Shale, covers a large portion of the Eastern United States, as is shown on an Energy Information Administration map, as well as a map that accompanies an article at  

Ohio Governor John Kasich announced that he is thrilled by the prospect for the job creation that will accompany development of the Utica Shale in Ohio.

Shale plays that produce oil, including the Eagle Ford and Bakken, as well as emerging shale plays such as the Utica and Tuscaloosa Marine Shale, could greatly reduce this country's dependence on foreign sources of oil

Senator Vitter to Block Nominee Until Leases Extended

Louisiana Senator David Vitter announced on August 3, 2011 that he will block the nomination of Rebecca Wodder to serve as Assistant Secretary for Fish and Wildlife and Parks in the U.S. Department of Interior until the agency extends the terms for hundreds of leases for drilling in the Gulf of Mexico that are set to expire this year.

Oil and gas leases generally have clauses providing for expiration of the lease after a specific term unless the leaseholder is drilling, or producing oil or gas from one or more wells previously drilled in the leased area.  But the moratorium that followed the Deepwater Horizon incident, and the slow pace of the Bureau of Ocean Energy Management, Regulation and Enforcement in granting permits for drilling have prevent many leaseholders from drilling.  Senator Vitter explained:

Since the moratorium, oil and gas exploration in the Gulf of Mexico has been dramatically curtailed,” Vitter said. “In 2011 alone, more than 300 offshore leases in the Gulf of Mexico are due to expire. If these leases are allowed to expire, they will revert to the federal government, killing jobs and cutting off potential revenue from exploration and production. The U.S. economy will greatly benefit by allowing the offshore energy industry to get to work and stay working. Even President Obama said he’d extend the leases, and I intend to hold the administration to that."

BOEMRE Issues Conditional Approval for Shell's Plan for Drilling in Beaufort Sea

On August 4, 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) announced that it has granted conditional approval for Shell's revised Exploration Plan to drill as many as four shallow water exploration wells in Alaska's Beaufort Sea beginning in July 2012.  The area where the drilling would take place is covered by leases acquired by Shell in lease sales conducted in 2005 and 2007.  The conditions that accompany the approval include requirements that Shell secure all necessary permits from other agencies, including the Environmental Protection Agency, the U.S. Fish & Wildlife Service, and the National Marine Fisheries Service.

In early May, this blog reported that Shell had filed a revised Exploration Plan for drilling n the Beaufort Sea, which is located off Alaska's northern coast.

BOEMRE's approval of Shell's exploration plan follows the bureau's completion of a site-specific Environmental Assessment to examine potential environmental impacts of the drilling.  BOEMRE's announcement stated that the bureau had "found no evidence that the proposed action would significantly affect the quality of the human environment."  For that reason, BOEMRE stated that an Environmental Impact Statement would not be required.

BOEMRE's website has a page with links to various important documents relating to the drilling project, including Shell's 198-page revised Exploration Plan, BOEMRE's 238-page Environmental Assessment, BOEMRE's Finding of No Significant Environmental Impact.

Hydraulic Fracturing Litigation -- Trespass Claims

My July 18, 2011 post noted that, in most hydraulic fracturing litigation, plaintiffs assert claims based on multiple legal theories, including trespass.

A trespass occurs if the defendant makes an unauthorized entry onto the plaintiff's property or causes a thing to make an unauthorized entry.  See Restatement (Second) Torts § 158.  It is well‑established that a trespass can occur by the unauthorized entry into the subsurface of the plaintiff's property.  See id. at § 159; Gliptis v. Fifteen Oil Co., 16 So. 2d 471 (La. 1944).  If a trespass is intentional, a defendant can be liable even if the plaintiff cannot show harm.  See Restatement (Second) Torts § 158. 

But if a trespass is not intentional, and the defendant's activity was not ultrahazardous, the plaintiff must show actual harm in order to recover.  See id. at § 165.  It will not be enough for the plaintiff merely to show that a substance has encroached upon his land.  And, if the physical intrusion is neither intentional nor the result of negligence, the plaintiff will not be entitled to recover even if he can show injury.  See id. at § 166.  Thus, if an intrusion onto plaintiff's property was not intentional, a defendant can avoid liability unless the plaintiff can prove negligence and actual damages. 

Various other defenses might also apply, including one based on the "rule of capture."  The rule of capture is an oil and gas doctrine.  It provides that if a landowner drills a well on his property, and the well does not trespass onto his neighbor's property, then the landowner is entitled to all the oil or gas produced by his well, even if the well drains oil or gas from beneath his neighbor's property.  See Kelly v. Ohio Oil Co., 49 N.E. 399 (Ohio); see also Patrick H. Martin and Bruce M. Kramer, Manual of Oil and Gas Terms (14th ed. 2009).

In Coastal Oil & Gas v. Garza Energy Trust, 258 S.W.3d 1 (Tex. 2008), the plaintiff alleged that the defendant drilled a well on neighboring property, and that the fracturing fluid and proppants(but not the well bore) encroached into the subsurface of the plaintiff's property.  The plaintiff alleged that the encroachment constituted a trespass, and that the trespass harmed plaintiff by facilitating the drainage of minerals from beneath the plaintiff's land.  The Texas Supreme Court held that, because the only harm alleged by the plaintiff was drainage, the rule of capture precluded recovery.  Accordingly, the court did not have to decide whether the intrusion of fracturing fluid would have constituted an actionable trespass if there had been some harm other than drainage.

In some cases, unitization might provide a defense.  Unitization is a regulatory action or contractual agreement that modifies the rule of trespass by providing that all landowners holding property within a particular unit area will share in production of any oil or gas produced from within the unit, without regard to where the well is drilled.  See, e.g., Hunter Co., Inc. v. McHugh, 11 So. 2d 495 (La. 1943).  Unitization modifies property rights by displacing the rule of capture.  In Wainoco v. Nunez, 488 So. 2d 955 (La. 1986), the plaintiff's land had been unitized withthe neighbor's land.  A well was drilled from a well pad on the neighboring property, but the drilling deviated form vertical (apparently, unintentionally), and the well allegedly intruded into the subsurface of the plaintiff's land at some deep depth.  The plaintiff alleged a trespass, but the Louisiana Supreme Court held that the unitization order modified property rights, with the result being that plaintiff did not have a claim for subsurface trespass.

Finally, if the defendant has operated pursuant to government‑issued permits, that may provide a defense to a trespassing claim.  In several cases, plaintiffs have complained that fluids from an injection disposal well on neighboring property have intruded into the subsurface of plaintiff's land.  Courts generally denied recovery in those cases.  Although those courts generally have based their holdings on a plaintiff's inability to show actual harm, the language of the opinions also suggest that courts are reluctant to hold a defendant liable for actions he undertook pursuant to a valid permit.  See, e.g., Chance v. BP Chems., Inc., (Ohio 1996); Boudreaux v. Jefferson Island Storage & Hub, 255 F.3d 271 (5th Cir. 2001).