Environmental & Energy Law Brief

On Friday, the U.S. Environmental Protection Agency released additional test results from water samples collected in Dimock, Pennsylvania and again declared that none showed unsafe levels of contaminants.  The recently-released test results are consistent with previous test results in which EPA found no unsafe levels of contamination.

An EPA spokesman confirmed that the test results "did not show levels of contaminants that would give EPA reason to take further action."

The EPA's testing program was initiated in response to complaints from residents of Dimock about their water quality, which some of the residents blamed on local oil and gas activity, including hydraulic fracturing.  The EPA has now completed four rounds of water sampling and testing, with samples being collected from approximately 61 homes in the small northeastern Pennsylvania town.  The EPA has not found any results that fall outside federal drinking water standards.

A spokesman for Cabot Oil & Gas Corporation, which operates in the area, said: "Cabot is pleased that EPA has now reached the same conclusion of Cabot and state and local authorities resulting from the collection of more than 10,000 pages of hard data — that the water in Dimock meets all regulatory standards."

The test results (a large file) can be found here.

Yesterday, President Barack Obama issued an executive order creating an interagency working group to coordinate federal government policies relating to natural gas development.  The executive order states that natural gas "production creates jobs and provides economic benefits to the entire domestic production supply chain, as well as the chemical and other manufacturers, who benefit from lower feedstock and energy costs."  Further, "with appropriate safeguards, natural gas can provide a cleaner source of energy than other fossil fuels." 

For these reasons, it is vital that we take full advantage of our natural gas resources, while giving American families and communities confidence that our natural and cultural resources, air and water quality, and public health and safety will not be compromised."

The new group, called the "Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources," will be chaired by the Director of the Domestic Policy Council.  Other members will include representatives from:

(1) the Department of Defense;

(2) the Department of the Interior;

(3) the Department of Agriculture;

(4) the Department of Commerce;

(5) the Department of Health and Human Services;

(6) the Department of Transportation;

(7) the Department of Energy;

(8) the Department of Homeland Security;

(9) the Environmental Protection Agency;

(10) the Council of Environmental Quality;

(11) the Office of Science and Technology Policy;

(12) the Office of Management and Budget;

(13) the National Economic Council; and

(14) such other agencies or offices as the group's chair may invite to participate. 

A group of scientists recently issued a report in which they conclude that methane is commonly found in water wells in northern Pennsylvania, but that the presence of methane is unrelated to hydraulic fracturing of the Marcellus Shale.  The scientists based their conclusions on the analysis of samples collected from more than 1700 water wells in Susquehanna County, Pennsylvania prior to proposed natural gas drilling. 

In the report published in December in Oil & Gas Journal, the scientists stated that methane is "nearly ubiquitous in water wells in this region, with over 78% of the water wells exhibiting detectable methane concentrations."  The scientists found no correlation between the presence of methane and the existence of nearby oil and gas activity, but they found a "clear correlation" with natural topography.  "Specifically, water wells located in lowland valley areas exhibit significantly higher dissolved methane levels than water wells in upland areas, with no relation to proximity of existing gas wells."

The scientists stated that each of their three findings ─ that methane in water wells is common in the area, that it is unrelated to hydraulic fracturing, but that it is related to topography ─ is supported by additional evidence.  For example,

Technical literature and historical publications confirm the presence of methane gas in natural seeps and water wells in this region for many decades, long before shale gas drilling operations were initiated in 2006." 

In fact, in 2004, the Pennsylvania Department of Environmental Protection published a "Fact Sheet" on methane in water wells.  Further, the scientists noted that, in an earlier 2011 study, the Center for Rural Pennsylvania sampled 48 water wells located at varying distances from natural gas wells in Pennsylvania, finding "no significant relationship of methane concentrations to distance from a gas well."

As for their conclusion that there is a relation between topography and methane concentrations, the scientists noted that similar results were obtained in a study conducted in West Virginia by the U.S. Geological Survey from 1997 to 2005.  In that study, the USGS sampled 170 water wells, finding that methane concentrations exceeding 10,000 ppb "only in wells located in valleys and hillsides, rather than hilltops."  Moreover, the conclusion is also supported by anecdotal testimony of water well drillers in Susquehanna County, who report that methane is frequently found in water wells in the County, but that "water wells with gas shows are most commonly observed in the valleys."   

In their recent report, the scientists also addressed a study published by a group from Duke University earlier in 2011.  Like the scientists who published the recent report in Oil & Gas Journal, the Duke researchers found that it is common for water wells to contain methane, without regard to whether the water wells are located near oil and gas activity.  But the Duke researchers, who based their study on a much smaller data set, concluded that higher levels of methane can be linked the existence of nearby oil and gas activity. 

The Duke group based their conclusions in part on using isotopic analyses of their water samples to distinguish between biogenic methane and thermogenic methane.  Biogenic methane is formed at relatively shallow depths beneath the earth's surface through biological processes associated with the decay of organic matter.  Thermogenic methane is created through non-biological processes, typically much deeper underground, when organic material is subjected to significant  heat and pressure.  Because the natural gas for which oil and gas companies are drilling is the thermogenic methane that is found in deeper formations, the existence of biogenic methane in a water well would not likely be caused by oil and gas activity.  

The Duke researchers concluded that, whenever they found biogenic methane in a water well, the presence of methane was not caused by oil and gas activity.  But when they found thermogenic methane in a water well, they concluded that oil and gas activity likely had caused the methane to be present.

The group of scientists that published their findings in Oil & Gas Journal noted, however, that some relatively shallow sandstones contain thermogenic methane, and that many water wells are drilled deep enough to intercept those sandstones.  Thus, the presence of thermogenic methane in a water well does not necessarily indicate the methane's presence is the result of by oil and gas activity. 

Further, the scientists explained that thermogenic methane from different formations sometimes can be distinguished by isotopic analyses, in the same way that thermogenic and biogenic methane can be distinguished.  Indeed, thermogenic methane from the Marcellus Shale has a different isotopic signature than the thermogenic methane from the shallower sandstones found in northern Pennsylvania, and the isotopic signature of the thermogenic methane found in some of the Duke study's samples is more consistent with methane that comes from the shallower sandstones, rather than from the Marcellus Shale.  Accordingly, the scientists state that the Duke study's results do not support a conclusion that Marcellus Shale drilling or hydraulic fracturing caused the presence of methane in the water wells sampled for the Duke study.

Postscript: Multiple readers have asked about the source of funding for the study reported in the Oil & Gas Journal, and one reader asked about funding of the Duke study.  I understand that the study discussed in the Oil & Gas Journal was supported by Cabot Oil & Gas.  The Duke study was supported by Fred and Alice Stanback, who are financial donors to various environmental causes and organizations, and by the Duke Center on Global Change, an interdisciplinary center at Duke that focuses on climate change and other environmental issues.

Last week, the West Virginia legislature passed a bill to regulate hydraulic fracturing and shale gas development.  The Governor supported the legislation, called the Natural Gas Horizontal Wells Control Act. 

The Act applies to any horizontal well, other than a coalbed methane well, if it "disturbs three acres or more of surface," excluding pipelines and roads, or if more than 210,000 gallons of water are used at the well in any thirty day period.  The Act requires oil and gas operators to

• obtain a drilling permit before commencing drilling or even beginning site preparation work   
• publish a legal advertisement in the county where a well will be located prior to applying for a permit 
• give notice to surface owners, as well as coal seam owners, operators, and lessees of the oil and gas operator's application for a drilling permit    
• give advance notice before entering the property to conduct seismic operations  
• give advance notice before entering the property to drill       
• develop an erosion and sediment control plan for each well site   
• develop a water management plan    
• declare in the permit application what additives the operator anticipates using in any hydraulic fracturing fluid     
• disclose, as part of a mandatory completion report, the additives actually used in the fracturing fluid   
• keep records of the amount of flowback water recovered from the hydraulic fracturing   
• keep records of the amount of produced water   
• reclaim the well site after operations are complete by doing such things as sodding or planting seeds at the well site, and removing drilling equipment and supplies   
• fill pits, except in certain specified circumstances   
• dispose of cuttings in an approved manner  
• locate wells at least 250 feet from any existing water well, 650 feet from any occupied dwelling (and any building above a specified size that houses animals), 100 feet from any lake or perennial stream, 300 feet from any naturally reproducing trout stream, and 1000 feet from of any intake of a public water supply
• pay for surface damages   
• post either a $50,000 bond for each well or a blanket bond of $250,000, payable to the state, to guarantee performance of the operator's duties.

The Act gives the surface owner and coal interests for the location where a well will be drilled the right to give written comments regarding a drilling permit application to the Department of Environmental Protection, and requires DEP to consider those comments before granting a permit.

The Act also  addresses civil litigation in which a surface owner alleges that his water well has been contaminated by oil and gas operations.  The Act establishes a rebuttable presumption that an oil and gas operator's activities have caused any contamination of a water well located within 1500 feet of the operator's well pad if the contamination occurs within six months of the completion of the gas well.  The oil and gas well operator may rebut the presumption by proving  by a preponderance of the evidence that the water was contaminated before the gas well was drilled, that the water well owner refused to allow the operator access to his property to test the water prior to drilling the gas well, or that something other than the oil and gas activity caused the contamination.  

In cases in which the West Virginia DEP determines that oil and gas activity has caused contamination, the Act also requires the operator to provide a replacement water supply, even if the operator disputes the DEP's determination, until the DEP or a court orders otherwise.  This requirement is in addition to any other relief that may be ordered by a court. 

The Act establishes fines and, in certain circumtances, the possibility of imprisonment for violations of the Act.

In addition, the Act addresses enforcement.  It provides for certain minimum qualifications for the Department of Environmental Protection's well supervisors and well inspectors.  For example, to qualify for those positions, an applicant must have at least two years of relevant oil and gas industry experience (or at least one year of experience if the applicant satisfies certain educational requirements), and must pass a written and oral examination.  The Act also requires that oil and gas supervisors be paid at least $40,000 per year and that inspectors be paid at least $35,000 per year.  To help fund DEP's enforcement activities, the Act increases permit fees to $10,000 for the first well drilled from a single pad, and to $5000 for subsequent wells drilled from the same pad.

The bill is lengthy, but can be found at the website of the West Virginia legislature (click on "Enrolled Version - Final Version" for HB 401 of the 2011 4th Special Session).

At Louisiana's state lease sale on October 12, 2011, the Department of Natural Resources accepted bids to lease more than 6000 acres of state‑owned land in East Carroll Parish, an area which historically has seen relatively little oil and gas activity.  The bidding on tracts in East Carroll appears to have been prompted by interest in the "Brown Dense," a shale formation that stretches across South Arkansas and North Louisiana, and which is expected to be an oil play.  The Brown Dense is sometimes called the "Lower Smackover" because it is located below the "Smackover," a formation from which companies have produced oil and gas for several decades in Louisiana. 

The winning bids for each of the tracts in East Carroll provided for a bonus of approximately $304 per acre, delay rentals of about $150 per acre, a 20% royalty, and a three‑year primary term.  In addition to the tracts for which bids were accepted at the October lease sale, private interests have nominated tracts of state‑owned water bottoms totaling more than 3000 acres in East Carroll for bid at the upcoming December 14, 2011 state lease sale.

Activity in the Brown Dense is at an early stage.  Southwestern Energy has received a permit for a Brown Dense well in Claiborne Parish, and is expected to begin drilling the well this year.  Southwestern already has begun drilling a Brown Dense well in Columbia County, Arkansas, and has plans to drill as many as ten Brown Dense wells in 2012.  XTO, a subsidiary of ExxonMobil, also has obtained a permit for a well in Claiborne Parish.  In addition, Devon Energy has obtained a permit for a well in Morehouse Parish.

The Oil and Gas Law Brief previously discussed the Brown Dense in posts dated August 31 and September 11, 2011.  The Department of Natural Resources has a page on its website with information regarding state lease sales, which are conducted by DNR's State Mineral and Energy Board.

The Secretary of Energy Advisory Board on shale gas production issued its second "ninety day" report, dated November 18, 2011.  The group's first report, dated August 18, 2011, stated that shale gas production is important to the economy and our nation's energy security, but that several changes to regulations and procedures should be made to address environmental issues.  The first report made recommendations relating to reducing emissions, requiring disclosure of fracturing water composition, improving well construction standards, and prohibiting the use of diesel in fracturing fluid (see August 29, 2011 Oil & Gas Law Brief).  

The second report does not contain much in the way of new recommendations or conclusions.  Instead, it primarily discusses implementation of the recommendations contained in the first report.  For example, the second report expresses the Advisory Board's disappointment that there has not been more progress toward implementing the Board's prior recommendations, but the second report also acknowledges that progress has been made and that it has been a relatively short time since the release of the first report.  For each of the Advisory Board's prior recommendations, the second report also discusses which entity or entities would have to take action in order to implement the recommendation — the federal government, state governments, or some other organization.

In some reports, the Advisory Board is referenced as "SEAB."

Pennsylvania Governor Tom Corbett announced plans to implement numerous recommendations made by the Marcellus Shale Advisory Commission, "including changes to enhance environmental standards, an impact fee, and a plan to help move Pennsylvania toward energy independence."

The recommendations Corbett plans to implement include:

• Increasing well setback distances for Marcellus wells from private water from 200 feet to 500 feet, and to 1000 feet from public water systems
• Increasing setback distances from 100 feet to 300 feet from streams, rivers, ponds, and other bodies of water
• Increasing bond requirements from $2000 to $10,000 for wells
• Increasing blanket bonds (that a company can post in lieu of bonds for individual wells) from $25,000 to $250,000      
• Expanding an unconventional gas operator's "presumed liability distance" for water well contamination from 1000 feet to 2500 feet      
• Extending the duration of presumed liability from 6 months to 12 months after completion of a gas well        
• Giving the Department of Environmental Protection the ability to take quicker action to revoke permits from any operator who consistently violates regulations        
• Doubling the authorized penalties from $25,000 to $50,000 for civil violations of environmental regulations         
• Doubling daily penalties from $1000 to $2000     
• Subjecting wells to an impact fee of $40,000 in the first year, $30,000 in the second year, $20,000 in the third year, and $10,000 in the fourth year.

Under Governor Corbett's plan, 75 percent of the revenue from impact fees would be retained at the local level, with 25 percent going to the State.  Much of the State's share would be dedicated to roads.

Governor Corbett also announced plans to promote energy independence and reduce reliance on foreign oil by helping convert fleets of school buses and mass transit vehicles to the use of natural gas, and developing "Green Corridors" with refueling stations for natural gas vehicles at least every 50 miles.

Governor Corbett's announcement stated that most of the Marcellus Shale Advisory Commission's regulations can be implemented by directives he will grant to executive agencies, but that about a third of the recommendations will require legislative action.  Corbett stated that he would submit a proposal to the legislature in the near future.

A Pennsylvania appellate court recently issued a decision that will create uncertainty regarding who owns the right to produce natural gas from the Marcellus Shale in certain circumstances -- namely, whenever a chain of title contains a deed that grants the right to produce "minerals," without specifically referring to a right to produce natural gas. 

 In Pennsylvania, as in most states, the general rule is that the surface owner has the right to produce such substances as coal, oil, and natural gas from beneath his land, unless he or a prior owner of the surface has executed a deed that grants the right to produce one or more of those substances to someone else. 

In Butler v. Charles Powers Estate, 2011 WL 3906897 (Pa. Super.), one of the issues was whether a deed that granted the right to produce "minerals and Petroleum Oils" included a grant of the right to produce natural gas from the Marcellus Shale.  Many people who follow Pennsylvania oil and gas law would have concluded that the deed did not grant a right to produce natural gas, based on prior Pennsylvania Supreme Court decisions holding that:

• the right to produce coal includes the right to produce natural gas contained within the coal, U.S. Steel Corp. v. Hoge, 468 A.2d 1380 (Pa. 1983)
• but a grant of the right to produce "all minerals" generally does not include the right to produce oil, Dunham v. Kirkpatick, 101 Pa. 36 (1882)
• the grant of a right to produce "minerals" does not include the right to produce oil or natural gas, Highland v. Commonwealth, 161 A.2d 390 (Pa.), cert. denied, 81 S. Ct. 234 (1960), and
• the right to produce "oil" does not include the right to produce natural gas, Bundy v. Myers, 94 A.2d 724, 725 (Pa. 1953).  

And the lower court in Butler ruled as many people would have predicted, issuing a judgment based on the parties' pleadings (before evidence was taken) that the deed's grant of a right to produce "minerals and Petroleum Oils" did not include a grant of the right to produce natural gas from the Marcellus Shale.  But the appellate court reversed, remanding the case to the lower court to give the appellant the chance to prove whether the deed's grant included the right to produce natural gas from shale. 

The appellate court reasoned that the prior Pennsylvania Supreme decisions did not answer such questions as whether shale is a "mineral," whether natural gas found in shale "constitutes the type of conventional natural gas contemplated in Dunham and Highland," and whether there should be a rule for shale similar to the rule for coal that the person who owns the coal owns the right to produce natural gas from the coal.

At some level, there is logic to the appellate court's suggestion that perhaps shale is analogous to coal, and that perhaps the person who owns the right to produce the shale should have the right to produce the natural gas found inside the shale.  On the other hand, a strong argument can be made that too much is being made of the fact that natural gas is located inside the shale because natural gas is always found inside the pore spaces of either coal or underground rock formations.  And the Pennsylvania Supreme Court has held that the right to produce coal includes the right to produce natural gas found in coal, but that that right to produce "minerals" does not include the right to produce natural gas found in rock formations.  Shale is a type of rock formation. 

The Butler appellate court's reference to "conventional" gas suggests that the court may have been influenced by the fact that hydraulic fracturing is used both in producing gas from coal and in producing gas from shale.  Perhaps the court believed that there is an  important distinction between gas tightly bound inside relatively impermeable rock, so that it can only be produced by use of hydraulic fracturing, versus gas in a rock whose permeability allows the gas to flow relatively freely.  But it is questionable whether the use of a similar production process should override what otherwise seemed to be a settled matter of property law regarding who owns the right to produce natural gas found in formations other than coal beds.

But whatever the merits of shale being treated like other rock formations versus shale being treated like coal, Butler will have an unfortunate result -- it will create confusion about who owns the right to produce natural gas from shale if there is a deed that grants him the right to produce "minerals," but the deed does not expressly refer to a right to produce gas.  This question ultimately will have to be resolved by the Pennsylvania Supreme Court.  It is an important enough issue that the Supreme Court should grant immediate review of the issue. 

If the Pennsylvania Supreme Court does not grant immediate review, the Butler case will go back to the trial court for formal discovery, followed by a trial, followed by a new trip to the appellate court, and only after all of those steps would the case be ready for potential review by the Pennsylvania Supreme Court.  That process easily could take a couple of years, and perhaps longer.  It would be very unfortunate to allow doubts about title to fester for that long.  Such doubts would not only discourage drilling on property affected by deeds referring to the right to produce "minerals" and not referring to "gas" expressly, but such doubts also will create uncertainty about property values for property that may or may not include the right to produce shale gas, and create uncertainty about whether some oil and gas leases were granted by the appropriate lessors.  Such doubts could harm a large number of innocent persons.

The New York Department of Environmental Conservation announced today its release of a a lengthy Economic Assessment Report that evaluates the economic effects that would result from the use of hydraulic fracturing within New York.  The DEC stated that its analysis "confirms that high-volume hydraulic fracturing activities could provide a substantial economic boost for the state in the areas of employment, wages and tax revenue for state and local governments."

The New York DEC estimated that the use of high volume hydraulic fracturing in New York would lead to the creation of over 17,600 full-time-equivalent construction jobs, more than 7100 jobs for individuals who will operate wells, and more than 29,100 indirect jobs (this is under an average scenario; the DEC also included low-range and high-range estimates).  The DEC concluded that the employee income from those jobs could be between $621.9 million and $2.5 billion per year.

The DEC estimated that hydraulic fracturing activity also would benefit state and local government.  "Using conservative tax rates at maximum build-out, the state could receive between $24 million and $125 million a year in personal income tax receipts."  In addition, the state could receive lease revenue from subsurface drilling beneath state lands.  The report DEC stated that use of hydraulic fracturing could result in increased use of some public services, such as roads, but implied that the increased cost to the state would be much less than the economic benefit.

The DEC estimated that increased tax revenue to local government also would be significant.  This could include "a substantial increase in sales tax receipts," as well as "an increase in ad valorem property tax revenue."

The DEC released the Economic Assessment Report today as an addition to its Supplemental Generic Environmental Impact Statement (SGEIS) that it issued earlier this Summer (see the July 9, 2011 post in the Oil & Gas Law Brief, which includes links to the SGEIS).  A public comment period on the SGEIS begins today and runs through December 12, 2011.  The DEC plans to issue proposed regulations in early October 2011, with a public comment period on the regulations running from the release of those regulations until December 12.  The DEC plans to hold four public hearings on the subject in different parts of the state, with specific locations and dates being announced in October.

The information released by the DEC today included: its announcement; a two-page Fact Sheet that summarizes economic impacts of hydraulic fracturing; a two-page Fact Sheet that summarizes local and community impacts; and the full, approximately 250-pages-long Economic Assessment Report.  

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. 

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.

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.

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.

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.

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.

This post is part of my continuing series on hydraulic fracturing litigation.  In my July 25 post, I discussed one of the legal theories that some plaintiffs are asserting -- strict liability for an "abnormally dangerous" or "ultrahazardous" activity.  Today's post discusses defenses to such claims.

In defending against an abnormally dangerous activity claim, a defendant should not assume that the doctrine applies.  Louisiana is one of the states where hydraulic fracturing is being actively used.  Although Louisiana recognizes the concept of an ultrahazardous activity, 1996 tort reform legislation limited the doctrine to just two types of activities ─ blasting with explosives and pile driving.  See Acts 1996, 1st Ex. Sess. No. 1 § 1 (amending Civil Code art. 667).

 Texas is another state where hydraulic fracturing is frequently used.  The Texas Supreme Court has suggested that Texas does not recognize the abnormally dangerous activity doctrine.  See Turner v. Big Lake Oil, 96 S.W.2d 221 (Tex. 1936).  In Turner, the defendant was storing a large quantity of produced water (salt water that sometimes is produced simultaneously with oil).  The water escaped, and flowed onto the plaintiff's land, killing vegetation and contaminating watering holes used by the plaintiff's cattle.  The plaintiff filed suit, alleging strict liability based on Rylands v. Fletcher, 3 H.L. 330 (1868).  The Texas Supreme Court rejected that claim, stating that the plaintiff would have to establish that the defendant had been negligent because Texas did not recognize the rule of Rylands v. Fletcher.  Thus, the abnormally dangerous activity theory of strict liability should be unavailable in hydraulic fracturing litigation if either Louisiana law or Texas law applies.

 Further, even in states that recognize the abnormally dangerous activity doctrine, a defendant can argue that hydraulic fracturing is not an abnormally dangerous activity.  More than one million wells have been hydraulically fractured, and there are few, if any, documented cases in which hydraulic fracturing has caused contamination of groundwater.  In addition, a defendant could present expert testimony that risks can be addressed by use of proper care in the casing and cementing of wells.  Further, hydraulic fracturing provides substantial benefits to society.  Moreover, a defendant can argue that he was not fracturing in an inappropriate place, and that instead he was fracturing right where he should ─ where geophysical evidence and prior drilling indicate a productive shale formation exists.  All these arguments can be used to assert that the factors examined by courts to determine whether an activity is abnormally dangerous weigh against hydraulic fracturing being deemed abnormally dangerous. 

 Indeed, in a case in Pennsylvania, a court denied the defendants' Federal Rule of Civil Procedure 12(b)(6) motion to dismiss an ultrahazardous activity claim, but suggested in dicta that it had doubts that plaintiffs' ultrahazardous activity claim would survive a summary judgment motion later in the case.  See Berish v. Southwestern Energy Production Co., 763 F. Supp. 2d 702, 706 (M.D. Pa. 2011).

 Even if a court deems hydraulic fracturing to be ultrahazardous, there still are defenses.  For example, § 523 recognizes that assumption of the risk is a defense.  Comment (b) to § 523 provides an example of assumption of the risk.  The comment states that, if a possessor of land, knowing the risk of blasting, consents to allow blasting on neighboring property, he cannot recover if he is harmed by the blasting.  Most oil and gas companies operate their wells pursuant to mineral leases.  If the lessor granted the lease knowing that the lessee might conduct hydraulic fracturing, and the lessor understood that fracturing allegedly has great risk, then assumption of the risk might bar the lessor's recovery.

 Further, authority exists for the proposition that strict liability does not apply if the type of harm asserted by the plaintiff is not the sort of harm that one would expect from the ultrahazardous nature of the defendant's activity.  See Restatement (Second) Torts § 519(2).  The classic example concerns blasting.  Strict liability may apply for damages caused by the explosive force of the blasting or by flying debris that results from the explosion, but strict liability would not apply if the plaintiff is a mink farmer who alleges that the blasting made his adult mink nervous, with the result that they killed their young.  See Foster v. Preston Mill Co., 268 P.2d 645 (Wash. 1954).  Thus, if a plaintiff alleged that some injury other than that which one normally would expect might be caused by the alleged hazards associated with hydraulic fracturing, strict liability might not apply. 

Contributory negligence also is a recognized defense.  See  Restatement (Second) Torts § 524.  This defense probably will not apply very often in hydraulic fracturing litigation, but it could apply in some circumstances.  For example, if a plaintiff drinks water after he suspects it is contaminated, and he later alleges he suffered personal injury from drinking the water, contributory negligence may apply.

Maryland Governor Martin O'Malley recently named the members of an Advisory Commission to study and make recommendations regarding shale gas production.

Maryland's Department of the Environment and Department of Natural Resources, in consultation with the Advisory Commission, will conduct a three-part study and present findings and recommendations as follows:

• By December 31, 2011, findings and related recommendations regarding the desirability of legislation to establish revenue sources, such as a State-level severance tax, and the desirability of legislation to establish standards of liability for damages caused by gas exploration and production
• By August 1, 2012, recommendations for best practices for all aspects of natural gas exploration and production in the Marcellus Shale in Maryland
• By August 1, 2014, a final report with findings and recommendations relating to the impact of Marcellus Shale drilling including possible contamination of groundwater, handling and disposal of wastewater, environmental and natural resources impacts, impacts to forests and important habitats, greenhouse gas emissions, and economic impact.

The Advisory Commission was formed as a follow-up to Governor O'Malley's June 6, 2010 Executive Order establishing the Marcellus Shale Safe Drilling Initiative.  The Executive Order, together with a fact sheet issued by the Maryland Department of the Environment, stated that development of shale gas through horizontal drilling and hydraulic fracturing can have several benefits, including the generation of lease payments to individuals and government, tax revenue, jobs, and economic activity, as well as fostering both greater energy independence for the United States and the production of an energy source that is the cleanest burning of all fossil fuels.

But, stated the Governor, shale gas drilling also raises public health, environmental, and natural resources concerns, including "possible effects on drinking water."

The Marcellus Shale extends beneath Garrett County and parts of Allegheny County in Western Maryland.  The Governor's Executive Order does not place a moratorium on the issuance of permits for shale gas drilling.  The Maryland Department of Environment's fact sheet states that the Department still has authority to issue permits, and that existing Maryland law also gives the Department authority "to place all reasonable conditions in permits necessary to provide for public safety and to protect public health, the environment and natural resources." 

The Advisory Commission’s first meeting will be held at 9:30 a.m. on Thursday, August 4, 2011, in Western Maryland, at the Lakeside Visitors Center at Rocky Gap State Park and will be open to public. 

The Commission will be chaired by David Vanko, Ph.D., a geologist and current Dean of The Jess and Mildred Fisher College of Science and Mathematics at Towson University. Other members include: State Senator George Edwards; State Delegate Heather Mizeur; Garrett County Commissioner James Raley; Allegheny Commissioner William Valentine; Oakland Mayor Peggy Jamison; Shawn Bender, division manager at the Beitzel Corporation and president of the Garrett County Farm Bureau; Steven M. Bunker, director of Conservation Programs, Maryland Office of the Nature Conservancy; John Fritts, president of the Savage River Watershed Association and director of development for the Federation of American Scientists; Jeffrey Kupfer, senior advisor, Chevron Government Affairs; Dominick E. Murray, deputy secretary of the Maryland Department of Business and Economic Development; Paul Roberts, a Garrett County resident and co-owner of Deep Creek Cellars winery; Nick Weber, chair of the Mid-Atlantic Council of Trout Unlimited; and Harry Weiss, Esquire, partner at Ballard Spahr.

An article in Platts, an industry-oriented publication, expressed concern that the 14-member Advisory Commission includes only one representative from industry, while it contains three environmentalists, as well as others believed to be sympathetic to those who are opponents of hydraulic fracturing. 

Many people are asking about the Tuscaloosa Marine Shale (I provided basic background on this shale formation in my July 4 post, including a map showing where the shale is located, and a link to a report in which geologists estimate that the Tuscaloosa Marine Shale, or TSM, contains about 7 billion barrels of oil).  A few of the questions being asked are -- When will we know the real potential of this shale play? Which companies are players in the TSM?  Are wells being drilled yet, and if so, where?

When will we know the real potential of this shale play? 

We already know that the amount of oil contained in the Tuscaloosa Marine Shale is huge.  Each shale play is different, but if operators can make the combination of horizontal drilling and hydraulic fracturing work as well in the Tuscaloosa Marine Shale as those techniques have worked in some other shale plays, the TSM will be a bonanza.  We should know more soon because companies already have started drilling in the TSM.  Of course, in some of the shale plays, it has taken operators some time to refine their techniques, but the results from the first few wells should provide some clues to the TSM's potential.

What companies are players in the TSM and where are wells being drilled?

One of the companies that already started drilling is Devon Energy.  It has started two wells in East Feliciana Parish -- the Lane 64 Well, which has Louisiana Office of Conservation serial number 243108, and the Beech Grove Land Company No. 68 Well, which has serial number 243337.  Using the wells' serial numbers, readers can follow the progress of the wells on the Louisiana Department of Natural Resources' SONRIS database.

Another company that is active in the TSM is Indigo II Louisiana Operating.  It has started drilling the Bentley Lumber 32 Well (serial no. 242407).  Also, Indigo has obtained a permit for the Bentley Lumber 23 Well (serial no. 243237) in Rapides Parish.

EnCana Oil & Gas (USA) Inc. has obtained a permit to drill the Weyerhaeuser 73 Well (serial no. 243414) in St. Helena Parish, and is been reported to be planning to reenter a well in Amite County in Mississippi for purposes of targeting the Tuscaloosa Marine Shale.

In addition, Denbury Resources has accumulated lease acreage in the TSM.

Those who are interested in the Tuscaloosa Marine Shale should also check out the website of Amelia Resources (a company that is marketing investments in mineral acreage it has obtained).  It has a page where the company has posted some additional background information.  In addition, one of the company's principals has a blog that discusses the TSM.

The Tuscaloosa Marine Shale has attracted the attention of people who work or invest in the oil and gas industry, as well as those who practice oil and gas law.  So, what is the "TSM," and why has it drawn so much interest?

The Tuscaloosa Marine Shale is a shale formation that extends in a band across the middle of Louisiana, from the State's western border with Texas, through several parishes, and on into a few counties in southeastern Mississippi.  The formation is located from 10,000 to 14,000 feet beneath the surface, and at some points is several hundred feet thick. 

One of the reasons that many people are excited about the Tuscaloosa Marine Shale is that it is a shale that contains oil.  In the last few years, shale plays that produce natural gas, such as the Haynesville, Barnett, and Marcellus, have received significant media attention, but some shale formations produce oil.  These include the Bakken in North Dakota and Montana, and the Eagle Ford in south Texas.  Prices of both natural gas and oil have dropped below levels they reached a few years ago, but the decrease in natural gas prices has been much greater.  For that reason, oil and gas companies are particularly interested in drilling in places where oil might be produced.  

This has contributed to a surge in drilling in the Bakken Shale in North Dakota.  In fact, the Baker Hughes drilling rig count shows that North Dakota is the state with the fourth largest active rig count -- behind Texas, Oklahoma, and Louisiana -- and that North Dakota has more active rigs than Louisiana if only on-shore rigs are counted.  The hunt for oil also has led to increased drilling in the Eagle Ford Shale in Texas.

The Tuscaloosa Marine Shale is a shale formation that could produce substantial quantities of oil.  A report published in 1997 by the Basin Research Institute (then part of LSU) estimated that the Tuscaloosa Marine Shale contains potential reserves of about 7 billion barrels of oil.  A recent Times Picayune article reports that such companies as Goodrich Petroleum, Devon Energy, Denbury Resources, and Indigo II Louisiana have accumulated significant lease acreage in the TSM area, and that Devon likely will be the first to drill, perhaps in East Feliciana Parish.  In years past, some wells were drilled into the TSM and produced small amounts of oil, but there are hopes that advances in hydraulic fracturing and horizontal drilling will enable companies to produce much more than in previous attempts.  In fact, Louisiana's Commissioner of Conservation Jim Welsh has been quoted as saying that the Tuscaloosa Marine Shale could be Louisiana's Eagle Ford.  

Every shale formation is different, and operators have not yet proven that the TSM will live up to the hopes many people have expressed for it, but if operators are able to produce oil profitably from the Tuscaloosa Marine Shale, it could be the site of the next big oil rush.

The French Senate has voted to outlaw hydraulic fracturing, making France the first country to enact legislation banning the process. 

Bloomberg's Tara Patel reports that the ban is comprehensive, prohibiting use of hydraulic fracturing to produce oil or gas, as well as banning all research using the process.  Companies that have existing permits for oil and gas exploration have two months to disclaim the use of fracking in France, failing which the companies' permits will be terminated.  Further, anyone conducting hydraulic fracturing within France will be subject to fines and imprisonment.

The vote in the French Senate was 176 in favor of the ban versus 151 against.  But the vote was not as close as might appear from that tally.  Much of the opposition came from the Socialist Party, whose members voted against the ban, but not because they support hydraulic fracturing.  Rather, the Socialists voted against the ban "for not going far enough." 

Given that the legislation provides for a complete ban of all fracking, as well as imprisonment of anyone who performs fracturing, it was not immediately clear how the French Senate could have gone further -- perhaps stipulating the guillotine for anyone conducting fracking, rather than mere imprisonment?  Perhaps a law banning all energy production, or a law banning all oil and gas activity, rather than just fracking?  The latter guess might be close to the mark.  One report implied that the Socialists would have preferred an outright ban on all development of shale resources, whether or not fracturing is used, though there are no indications that any companies would be interested in or capable of developing shale resources without using fracking.  France supplies very little of the oil or natural gas it consumes, and that now seems unlikely to change. 

The stock price of Toreador, a company that had been issued the most permits to explore for oil around Paris, has dropped 76 percent since January 1.  Toreador had permits for exploration of the shale resources beneath 700,000 acres of land, but those permits now may have very little value.  An analyst was quoted in another story as saying, "It doesn't look good for Toreador."

But lest anyone think that France is turning its back on modern industry, rest assured that the French still worry about the French economy, including the country's reputation for pastries and bread.  Indeed, the New York Times quoted a Parisian social worker, who expressed the following concern about the arrest of French politician Dominique Strauss-Kahn on attempted rape charges in New York: "People used to think about baguettes when they thought about France; now they think DSK." 

EPA has announced locations for seven case studies regarding the potential impacts of hydraulic fracturing on underground sources of drinking water.  The locations include two sites where hydraulic fracturing has not yet started, but is planned for the near future.  These two "forward‑looking" or "prospective" sites are located in:

• DeSoto Parish, Louisiana (Haynesville Shale)
• Washington County, Pennsylvania (Marcellus Shale).

Five of the locations are "retrospective" study sites, where hydraulic fracturing already has occurred.  These sites include:

• Killdeer and Dunn Counties, North Dakota (Bakken Shale)
• Wise and Denton Counties, Texas (Barnett Shale)
• Bradford and Susquehanna Counties, Pennsylvania (Marcellus Shale)
• Washington County, Pennsylvania (Marcellus Shale)
• Los Animas County, Colorado (Raton Basin, coalbed)

At the "forward‑looking" sites, the EPA will take samples and evaluate conditions through the entire life cycle of the well, beginning before the wellpad is constructed and drilling begins.  Groundwater samples from the area around each site will be analyzed for several substances, and samples of flowback water also will be analyzed.  The operator of the well at the Haynesville Shale site in DeSoto Parish, Louisiana will be Chesapeake, and work is expected to begin by this Fall.  The operator of the well at the "forward‑looking" Marcellus Shale site in Washington County, Pennsylvania will be Range Resources, and work likely will begin this Fall or sometime later.

EPA anticipates starting work at one or more of the "retrospective" sites within about four months.  For the "retrospective" study sites, the EPA has not yet defined the specific wells that will be included in the study, and therefore has not named the operators.  Samples also will be collected in the vicinity of the retrospective study sites and analyzed for various types of compounds.

The seven case study locations have different characteristics.  The Bakken Shale in North Dakota is a shale from which oil is produced.  The Raton Basin in Colorado is a site where coalbed methane has been produced.  The other five sites are locations where natural gas has been produced or will be produced from the Barnett, Haynesville, and Marcellus Shales.

The site studies are part of the EPA's previously‑announced study of the possible effects of hydraulic fracturing on underground sources of drinking water.  A preliminary report is expected in 2012, and a more detailed report in 2014.

The locations for the site studies were chosen from amongst dozens of locations suggested by various stakeholders, including public officials and the public, based on criteria in the EPA's study plan that was published in February 2012.  The EPA stated yesterday:

These criteria included proximity of population and drinking water supplies to activities, concerns about impaired water quality (retrospective only) and health and environmental impacts (retrospective only), and knowledge gaps that could be filled by the case study.  Sites were prioritized based on geographic and geologic diversity, population at risk, site status (planned, active or completed), unique geological or hydrology features, characteristics of water resources, and land use."

The EPA announced the seven sites in a statement released yesterday, and made additional information available in late afternoon, during conference calls with various stakeholders.  The EPA's study is important because it will influence public opinion on the subject of hydraulic fracturing, which has become controversial, with supporters and opponents of fracturing portraying the process in very different terms.  The EPA's study also likely will influence the views of public officials and regulators.

Montana's Board of Oil and Gas Conservation will hold a public meeting on June 15, 2011 to consider the adoption of proposed regulations that would require operators to disclose the chemical composition of hydraulic fracturing fluids for each well fractured in Montana.  The proposed rules would allow operators to refrain from disclosing the identity of any chemicals that are trade secrets.  If, however, authorities need to know the identity of the chemicals in order to respond to a spill or release, or if health professionals need that information for diagnosis or treatment of a person exposed to the chemical, disclosure would be required.

If Montana adopts the proposed regulations, it will be following a growing trend toward the general disclosure of fracking water composition, while protecting trade secrets.  This blog has previously reported on: Wyoming and Arkansas enacting regulations last year that require complete disclosure of fracturing water composition to regulators, and provide for making all the disclosed information public, except information that qualifies for trade secret protection; Texas enacting a law last month that will lead to regulations requiring the oil and gas industry to publicly disclose fracturing water composition, except for the identity of chemicals that qualify as trade secrets; the Department of Interior considering implementing a mandatory disclosure requirement for wells fractured on federal land; and two groups of state regulators recently launching a website, FracFocus, where many operators are voluntarily disclosing fracturing water composition on a well-by-well basis.

Europe is split on the issue of using hydraulic fracturing to develop shale gas.  Poland's turn in the rotating position of European Union President is coming up later this year.  Both Euractiv.com and EUobserver.com are reporting that Poland will use its tenure in the presidency to push the European Union to promote shale gas development.  A Polish official stated that increased shale gas development in Europe would help the EU achieve is goals for reducing emissions of carbon dioxide because natural gas is the cleanest burning fossil fuel.  Further, increased shale gas production would help decrease the EU's dependence on natural gas imports from Russia.

On the other hand, the French Parliament has begun debating legislation that would ban fracking.  According to reports, France is likely to ban hydraulic fracturing and even rescind a couple of permits that already have been granted for shale gas development via fracking.

The United States Department of Interior's Bureau of Land Management recently announced that BLM will "take a fresh look at commercial oil shale and tar sand plans issued under the prior administration."  For some people, this will raise two questions.  What is "oil shale"?  What are "tar sands"?

The term "oil shale" in particular might confuse some people.  Oil shale is something different than the shale formations that have been receiving so much attention recently in connection with hydraulic fracturing.  Those shale formations contain natural gas, or sometimes oil, but traditionally it has not been economical to produce that oil or gas.  In recent years, however, advances in hydraulic fracturing and horizontal drilling has made such production economically feasible (see my 3/28/11 post). 

Oil shale is something different.  Oil shale is a type of sedimentary rock that contains a solid hydrocarbon called "kerogen."  Oil shale is formed in a process similar to the processes which are believed to lead to the formation of natural gas or oil.  Organic material is deposited along with silt in sea bottoms.  Over time, the organic material is buried by more and more silt, and is subjected to heat and pressure.  Depending on the amount of heat and pressure, the organic material can be converted to natural gas, oil, or oil shale.

Oil shale can be mined like any other solid material.  If the oil shale is then heated in a surface container to a temperature between 750 and 930 °F, it undergoes a chemical change in which an oily liquid is formed.  This process is called "retorting."  The oily liquid, sometimes called "shale oil," can be upgraded and then sent to a refinery.  Because a chemical change takes place during retorting, the process is different than the process of melting a solid or the process of heating a viscous liquid to make the liquid flow more easily.   

Retorting generally is performed in a plant, but companies sometimes perform retorting while the oil shale still is in the ground (called "in situ retorting") by using vertical heaters placed in holes to raise the temperature to about 650 to 700 °F.  This saves the step of transporting the solid oil shale.  

Some people criticize the use of oil shale on environmental grounds, objecting to the mining process, the energy needed in retorting, and the need to do something with the solid material left after retorting.

The largest deposits of oil shale in the world are found in the United States in the Green River Formation that covers parts of Colorado, Utah, and Wyoming.  The Green River Formation is estimated to contain the equivalent of 1.2 to 1.8 trillion barrels of oil, with the recoverable portion of that being the equivalent of perhaps 800 billion barrels of oil.  At present rates of oil consumption, 800 billion barrels of oil could supply the entirety of U.S. oil demand for about 100 years.

In a later post, I'll discuss tar sands.

For those concerned with how states are doing at regulating hydraulic fracturing, there is some good news.  An independent organization that includes representatives from various stakeholders, including environmental organizations, has evaluated regulatory programs in four of the states that have hydraulic fracturing activity and has concluded that those four states are doing a good job.

The non-profit organization State Review of Oil and Natural Gas Environmental Regulations ("STRONGER") was formed in 1999 to evalute state environmental regulations that govern the oil and gas industry.  Since then, STRONGER has produced numerous reports.  Recently, it has issued reports on the regulation of hydraulic fracturing in Louisiana, Pennsylvania, Ohio, and Oklahoma.  Although STRONGER's reports include suggestions to improve the regulatory programs in those  states, the reports also conclude that each of the four states already is doing a good job at regulating hydraulic fracturing.

The three-person team that studied Louisiana's regulatory program included one representative each from the Earthworks Oil and Gas Accountability Project, the Independent Petroleum Association of America, and the Oklahoma agency that regulates the oil and gas industry.  These organizations represented, respectively, three groups of stakeholders -- environmentalists, industry, and regulators.

STRONGER's report praised Louisiana's regulatory program for preventing industry's overuse of water from underground sources of drinking water.  In the early stages of developing the Haynseville Shale in northwest Louisiana, operators typically were using water from an underground drinking water aquifer to supply the water they used in fracking.  After landowners complained that water levels in the aquifer were dropping, the Louisiana Department of Natural Resources (DNR) directed operators to use surface water whenver possible to supply their fracking needs, and  the operators' use of water from the drinking water aquifer decreased dramatically. 

STRONGER also praised the Louisiana DNR for its prompt review and adjustment of regulations in response to development of the Haynesville Shale, its actions to encourage water recycling, and its public outreach and education program.  STRONGER's report suggested that Louisiana could improve its regulatory program by: adjusting its standards for casing of wells; requiring more detailed information in well reports; providing more structured training for its inspectors; and requiring wells operators to develop and implement their spill prevention and control plans earlier in the drilling process than is now required.  

The other STRONGER reports similarly contain specific praise and specific recommendations for regulatory programs in Pennsylvania, Ohio, and Oklahoma.

Hydraulic fracturing and horizontal drilling are old technologies, but they have been used with increasing frequency in recent years.  The increased use has come about because improvements in the technologies associated with hydraulic fracturing and horizontal drilling have made it economically feasible to produce oil and gas from shale formations, something that was not feasible in the past.  With the increased use, has come publicity and a great deal of public interest.  What is hydraulic fracturing?

First, let's take a step back.  When oil or gas is found underground, it is not located in a big, open cavern.  It is found in the pore spaces of rocks.  To produce oil or gas, a company drills to an underground formation that it hopes will contain such a product.  The target formation typically will be at high pressure (because of the weight of all the layers or rock and sediment above it).  If oil or gas is present, it will move through the rock to the well pipe, and up the well to the earth's surface.  But how does the oil or gas move through rock to get to the well?  It does so by traveling from one pore space to the next, through interconnections between the pores.

Sometimes, a formation will contain oil or gas (not all formations do), but the interconnections between pore spaces are too small in number or narrow in size for oil or gas to flow very readily through the rock.  Such formations, sometimes called "tight," have low permeability -- a measure of how easily a fluid flows through a solid.  If a formation's permeability is too low, it will not be economically feasible to produce oil or gas form the formation with conventional techniques, even if the formation contains oil or gas. 

But what if you could create additional pathways for the oil or gas to flow through the rock?  That is where fracturing comes in (also sometimes called "fracking" or "fracing").  It creates fractures or cracks in the rock, so that oil or gas can flow through the fractures, rather than just flowing from one pore space to the next.  Starting in the late 1800s, companies sometimes would engage in fracturing by lowering an explosive charge into the well and detonating it.  Such "explosive fracturing" could significantly increase production, but it also could be dangerous. 

In 1949, hydraulic fracturing was commercially developed, and since then, it has been used in over one million wells.  In hydraulic fracturing, a fluid -- typically water and various additives -- is pumped into the well at high pressure.  The high pressure fluid causes the target formation to fracture or crack.  When the high-pressure fracking fluid is removed, the fractures would tend to close.  To prevent that, the fractures are propped open with "proppants," small particles that are carried into the fractures with the fracking fluid and which remain behind when the fluid is withdrawn.  Sand is a common proppant, but sometimes small, specially-manufactured ceramic particles are used.

As noted above, water is one of the most common fracking fluids.  In addition to the proppants, various other additives are mixed in with the fracking water.  These include corrosion inhibitors to protect the well's piping, biocides to prevent microbial growth, friction reducers to reduce the friction between the fracking water and the well pipe, and viscosity adjusters to help the fracking water carry the proppants into fractures.  After a fracking job is complete, much of the fracking water is recovered, though some remains in the target formation.  

Fracking has great benefits.  As I will discuss further in a future post, fracking generates jobs and tax revenue, and it promotes our national security by decreasing our reliance on foreign sources of energy.  Fracking even has environmental benefits because it often is used to produce natural gas, the cleanest burning of all fossil fuels.  As reporters Bruce Alpert and Chris Kahn have written, President Obama has called for increased use of natural gas and increased domestic production of oil.  Fracking is a vital tool for meeting those goals.  On the other hand, people also have raised environmental concerns, primarily questions about whether water supplies could be affected.  One thing is certain -- we will continue to hear more about fracking.