Golden Rules for a Golden Age of Gas

Last week the International Energy Agency released an interesting report entitled "Golden Rules for a Golden Age of Gas."  The gist of the report is that unconventional natural gas ─ shale gas, coalbed methane, and tight gas ─ is a vast energy source that can be safely and economically produced, but legitimate environmental concerns exist, and those concerns must be better addressed by industry and government, or political opposition will hamper the development of unconventional gas.

Natural gas is poised to enter a golden age, but will do so only if a significant proportion of the world's vast resources of unconventional gas ─ shale gas, tight gas and coalbed methane ─ can be developed profitably and in an environmentally acceptable manner."

The report states that a "bright future for unconventional gas is far from assured" because there are concerns about the footprint of drilling activity, water usage, air emissions, and the potential for groundwater contamination.  The report concludes:

The technologies and know-how exist for unconventional gas to be produced in a way that satisfactorily meets [the environmental] challenges, but a continuous drive from governments and industry to improve performance is required if public confidence is to be maintained or earned."

The report states that industry must commit to the highest practicable standards and government must devise science-based regulatory regimes in order to generate the public confidence necessary to overcome political opposition to the growth of unconventional gas.  The IEA's report outlines a series of "Golden Rules" for appropriate environmental and social practices that the IEA believes will generate sufficient public trust so that unconventional gas can meet its enormous potential.

The report is long (over 130 pages), but is interesting and thought-provoking.  You can get the high points from the Executive Summary, which is just over three pages long.  It is well worth reading if you are interesting in the development of unconventional gas, the opposition to that development, and the appropriate ways to address concerns regarding development of unconventional gas.

Hydraulic Fracturing: EPA Says Water in Dimock is Safe

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.

FERC Approves Construction of LNG Export Facility in South Louisiana

Last week, the Federal Energy Regulatory Commission authorized two subsidiaries of Cheniere Energy Partners to begin construction of facilities for the liquefaction and export of natural gas at the Sabine Pass LNG terminal in Cameron Parish, Louisiana, currently the site of LNG import facilities.  FERC approval for the export of natural gas is required by the Natural Gas Act.  Cheniere hopes to have its proposed export facility in operation by 2015 or 2016. 

Cheniere's export facility would be only the second LNG export facility in the U.S., though other companies recently have begun the process of applying for permits to build export facilities.  The only existing LNG export facility in the U.S. is in Kenai, Alaska.  It was built in 1969 and primarily exports LNG to Japan, the world's largest importer of LNG. 

Just a few years ago, analysts were projecting that the U.S. would be importing increasing amounts of liquefied natural gas in the future.  But domestic production of natural gas production has soared in the last few years, largely because companies have utilized improved hydraulic fracturing and horizontal drilling technologies to produce natural gas from shale formations.  Indeed, the United States Energy Information Administration predicts that the U.S. will be a net exporter of LNG within a few years. 

Louisiana Department of Natural Resources Secretary Scott Angelle offered his "congratulations and appreciation" to Cheniere and federal regulators "for working together moving this project forward — the first of its kind in a generation and the second in our nation's history — and for establishing a procedural path in providing new markets for domestic natural gas and new economic stability in our natural gas markets that could mean more exploration, more jobs and more countries around the world dependent on us for energy instead of the other way around."

Cheniere released a statement in which its Chairman and CEO, Charif Souki, states: "Obtaining approval from the FERC is one more milestone for our Liquefaction Project.  We will now finalize financing arrangements in order to commence construction of the first two LNG trains of our Liquefaction Project promptly."

The surge in U.S. production of natural gas, and the central role that production from shale formations has played in that surge is illustrated by the two graphs below.  The top graph shows total U.S. production of natural gas, which began trending sharply upward in 2005.  The bottom graph shows U.S. production levels of shale gas (natural gas produced from shale formations).

 

graph of Estimated annual U.S. dry shale gas production, 2000-2011, as described in the article text

Obama Creates Interagency Working Group to Coordinate Federal Policy Regarding Natural Gas Development

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. 

Pennsylvania Supreme Court Agrees to Hear Butler case and Resolve Dispute Over Right to Produce Shale Gas

On April 3, the Pennsylvania Supreme Court agreed to hear a case in which the parties dispute whether a deed that reserves the right to produce "minerals and Petroleum Oils" has the effect of reserving the right to produce natural gas from the Marcellus Shale. 

Until a few months ago, many legal observers would have thought that such a deed clearly did not reserve the right to produce shale gas (natural gas produced from a shale formation), but a Pennsylvania appellate court ruled in September 2011 that such language in a deed from the late 1800s was unclear, and that expert testimony or other evidence regarding the intent of the parties to the deed would be needed.  That case, Butler v. Charles Powers Estates, 29 A.3d 35 (Pa. App. Ct. 2011), created an uproar in oil and gas circles and generated confusion about who owns the right to produce shale gas in circumstances in which similar  language has been used in deeds.

The dispute arose recently, but the seeds for the dispute were planted more than a century ago.  In 1881, the Estate of Charles Powers sold a tract of land to Patrick Fitzmartin, reserving the right to one-half of all "minerals and Petroleum Oils" produced from the property.  In Butler, the heirs to the Estate of Charles Powers and the successors to Mr. Fitzmartin dispute whether the Powers heirs have any right to shale gas produced from the property.

Based on a straightforward, three-step analysis, most oil and gas lawyers would have thought that the heirs did not have any such right.  That reasoning goes as follows.  First, in Pennsylvania, as in most states, the landowner generally has the right to produce and keep such substances as coal, oil, and natural gas from beneath his land.  Thus, the Estate of Charles Powers relinquished its right to shale gas when it sold the land, unless the reservation of the right to one half of "minerals and Petroleum Oils" changes the result.

Second, although a person who sells land can reserve the right to substances produced from the land, the Pennsylvania Supreme Court previously had held that the right to produce "minerals" generally does not include the right to produce natural gas.  See Highland v. Commonwealth, 161 A.2d 390 (Pa.), cert. denied, 81 S. Ct. 234 (1960); see also Dunham v. Kirkpatick, 101 Pa. 36 (1882) (the right to produce "all minerals" generally does not include the right to produce oil).

Third, the Pennsylvania Supreme Court previously had held that the right to produce "oil" does not include the right to produce natural gas.  See Bundy v. Myers, 94 A.2d 724, 725 (Pa. 1953).  Thus, the right to produce "minerals and Petroleum Oils" would not include the right to produce natural gas.  

Based on such reasoning the Butler trial court ruled in favor of the successors to Fitzmartin and against the Powers heirs, ruling that the Powers heirs did not have a right to one-half the shale gas produced from the property.  But the appellate court ruled that the reservation of the right to one-half of "minerals and Petroleum Oils" was ambiguous.  Accordingly, the appellate court reversed the judgment for the Fitzmartin heirs and remanded the case to the trial court for testimony regarding the intent of the parties to the 1881 deed.

The appellate court based its reasoning in part of the fact that, in Pennsylvania, the right to produce coal generally includes the right to produce methane contained within the coal.  See U.S. Steel Corp. v. Hoge, 468 A.2d 1380 (Pa. 1983).  The methane found in coal often is attached tightly to the coal, but the methane can be produced by the use of such "unconventional" processes as hydraulic fracturing and dewatering of the coal. 

The appellate court reasoned that, similarly, shale gas (which is mostly methane) is bound tightly within the shale, but can be produced by the unconventional process of hydraulic fracturing.  Thus, concluded the appellate court, perhaps the right to produce natural gas from the Marcellus Shale should belong to the person who owns the right to the produce the shale, and perhaps shale should be classified as a "mineral."  If so, the Powers heirs would have the right to one-half of the shale gas produced from the land because they own the right to one-half the "minerals."  Thus, the issue becomes whether shale is a "mineral," and if so, whether the right to produce "minerals" includes the right to produce gas within the minerals.

Whatever the merits of shale gas being treated like coalbed methane, many oil and gas lawyers lamented that the appellate court's decision in Butler was unexpected and would have an unfortunate result.  Namely, the decision would create uncertainty about who owns the right to produce natural gas from shale whenever there is a deed that grants someone the right to produce "minerals" (unless the deed also happened to expressly grant the right to produce natural gas to the same person who has the right to produce "minerals").

Such uncertainty could discourage drilling on property affected by deeds referring to the right to produce "minerals" and lead to expensive litigation about who owns what rights.  It is fortunate that the Pennsylvania Supreme Court has agreed to resolve the issue.  A decision by the Pennsylvania Supreme Court is likely to be several months away.

Large Study Finds No Link Between Methane in Pennsylvania Water Wells and Hydraulic Fracturing

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.

West Virginia Governor Earl Ray Tomblin Signs Horizontal Well Act

The Office of West Virginia Governor Earl Ray Tomblin issued a press release on December 22 announcing that Tomblin has signed the Horizontal Well Act.  That legislation, which passed by wide margins in the West Virginia legislature, was discussed in the Oil & Gas Law Brief on December 19, 2011.

West Virginia Legislature Passes Bill to Regulate Shale Gas Development and Hydraulic Fracturing

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).

Tuscaloosa Marine Shale News

Indigo Minerals issued a press release today stating that its first horizontal well targeting the Tuscaloosa Marine Shale has "resulted in a new oil discovery in Central Louisiana."  The press release stated that the well recently flowed at a rate of 534 barrels of oil equivalent per day, with 80% of that production actually being oil, with the remainder being natural gas and natural gas liquids.  Indigo stated that the oil is a light, sweet crude. 

Indigo drilled the well, called the Bentley Lumber 34H #1, in northwest Rapides Parish, to the Tuscaloosa Marine Shale formation, which sometimes is called the "Louisiana Eagle Ford."  Indigo used a 15-stage fracture stimulation.

Indigo has assembled nearly 260,000 net mineral acres within the Tuscaloosa Marine Shale.  Indigo stated in its press release that it has identified several additional locations to drill horizontal wells in 2012.  But Indigo stated that it will attempt to find a joint venture partner before beginning its 2012 drilling program.

Devon completed its Beech Grove Land Company 68H No. 1 Well in East Feliciana Parish in late October 2011.  Devon's initial report to the Louisiana Office of Conservation, which recently became available, indicates that the well tested at 120 barrels of oil per day of production.

And, Amelia Resources states in its weekly scout report for December 7 that Encana's Board of Education #1H Well in Amite County, Mississippi is producing an average of 119 barrels of oil per day, plus 49 mscf per day of gas. 

Several other wells are in the process of being drilled, completed, or tested.  Thus, much more news should be available soon.

Brown Dense Generates Interest in Louisiana State Lease Sales

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.

Oil & Gas Lease Sale for Land in Wayne National Forest Delayed

The U.S. Forest Service announced on November 15 that it is postponing plans to conduct an oil and gas lease sale for approximately 3300 acres of land in the Wayne National Forest in southeastern Ohio. The sale, which was scheduled to take place by auction on December 7, 2011 (the news release regarding the postponement erroneously refers to the originally scheduled date as being December 7, 2012), had been announced on September 7, 2011.  The land at issue is located in Athens, Gallia, and Perry counties.

The delay is expected to last at least six months.  Wayne National Forest Supervisor Anne Carey stated that the purpose of the delay is to allow a study of the effects hydraulic fracturing and shale development might have on the surface.  The Wayne National Forest is managed under a plan developed in 2006, and Ms. Carey stated that oil and gas development techniques have changed since then.  She stated: "Conditions have changed since the 2006 Forest Plan was developed.  The technology used in the Utica & Marcellus Shale formations need to be studied to see if potential effects to the surface are different than those identified in the Forest Plan."

Some people have criticized the delay, noting that it will cost jobs.  Sources have estimated that development of shale resoures in Ohio could generate more than 200,000 jobs within three years (see press release of the Ohio Oil & Gas Education Program), though that figure includes the effect of development in all areas of the state.  The Forest Service estimates that the number of potential jobs affected by the delay in the Wayne National Forest lease sale will only be a small fraction of that number. 

The total size of Wayne National Forest is approximately 241,000 acres. 

Secretary of Energy Advisory Board Issues Second Report on Shale Gas Production

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."

Shipments of Oil by Rail Increasing Rapidly, Driven by Surge in Production from Bakken Shale in North Dakota

Within the U.S., about two-thirds of crude oil is transported by pipeline, but the Energy Information Administration reports that shipments by rail are increasing rapidly.  The volume of crude oil and refined petroleum shipped by rail increased by 9.1% during the first ten months of 2011, compared to the same period in 2010.  Shipments of crude oil have also increased as a fraction of total rail shipments.  The number of railcars transporting oil increased from 2% of all railcars in 2008, to 3% in 2009, 7% in 2010, and 11% so far in 2011.

The biggest reason for this is the surge in production of crude oil from North Dakota.  Driven by drilling in the Bakken Shale, North Dakota's rate of oil production has increased by more than a third this year, from 343,000 barrels per day in January to 464,000 barrels per day in September.  This rate of production already exceeds the capacity of the pipelines serving North Dakota, and is expected to continue increasing.  North Dakota now has more active drilling rigs than any states other than Texas and Oklahoma, and it has been predicted that North Dakota will pass California to become the fourth largest producer of oil in the U.S. next year.

Pennsylvania Governor to Implement Recommendations of Marcellus Shale Advisory Commission

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.

North Carolina Studies Possible Shale Gas Production

The areas of the country with ongoing or contemplated shale gas production continue to increase in number.  The North Carolina Department of Environment and Natural Resources (DENR) has launched a study of possible shale gas production.  The study was prompted by a geological survey that shows the potential for shale gas production from the Triassic Strata of the Deep River Basin in the central part of the state.  The survey discusses a shale that stretches across approximately 25,000 acres at depths of less than 3000 feet in Lee and Chatham Counties. 

DENR's website contains information about its planned study, existing regulations, upcoming public meetings that will be held October 10 and 18, information about how the public can submit comments via mail or email, a PowerPoint presentation made by the North Carolina Geological Survey to the Environmental Review Commission, and a circular about natural gas and oil in North Carolina.   

Pennsylvania Court's Ruling Will Create Confusion Regarding Right to Produce Gas from Marcellus Shale

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.

Brown Dense Begins to Attract Attention

The Brown Dense is a shale formation that stretches across North Louisiana and South Arkansas.  As reported in an August 31 post of the Oil and Gas Law Brief, the Brown Dense is a potential new oil play that is attracting substantial interest from the oil and gas industry.  Companies have acquired oil and gas leases covering hundreds of thousands of acres in the area where the Brown Dense is located, and are preparing to drill multiple wells this year and even more wells next year. 

The Brown Dense is now also starting to attract attention from the mainstream media.  Today's Times Picayune carried a story by Richard Thompson that focuses on the Brown Dense.  Thompson's story also discusses the Tuscaloosa Marine Shale, a potential new oil play that stretches across central Louisiana, and the Haynesville Shale, an existing natural gas play in northwestern Louisiana.  With oil prices remaining high and natural gas prices depressed, many oil and gas companies are expressing more interest in potential oil plays like the Brown Dense and the Tuscaloosa Marine Shale than in natural gas plays.

Below is a map that shows the relative locations of the Brown Dense, the Tuscaloosa Marine Shale, and the Haynesville Shale.

New York Issues Economic Assessment Report Regarding Hydraulic Fracturing

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.  

Louisiana's Proposed Regulation for Disclosure of Fracking Water Composition Appears on Track for Enactment

As reported on July 11, 2011 in the Oil and Gas Law Brief, Louisiana's Department of Natural Resources has proposed a regulation that would require operators to disclose the composition of the water used to hydraulically fracture wells in Louisiana.  DNR has accepted public comments regarding the proposed regulation, and a public hearing regarding the proposal was held on August 30, 2011.  The comments, including those from industry, have been generally favorable, and the proposed regulation appears to be on track for enactment without any change in language.  Unless something unexpected happens, the regulation likely will go into effect in late October 2011.

As reported in this blog's July 11 post, the proposed regulation would require operators to disclose

  • the volume of hydraulic fracturing fluid used
  • the types of additives used (for example, biocides, corrosion inhibitors, friction reducers, etc.), as well as the volume of each type
  • the trade name and supplier of each additive, and 
  • a list of the chemical compounds contained in the additives, along with the maximum concentration of each compound.

If the identity of the chemical compound is a trade secret, the operator would be excused from identifying the compound, but would be required to identify the chemical family to which the compound belongs.

Louisiana's proposed regulation would require that the mandated disclosure be made either to the Office of Conservation or to FracFocus, a website operated by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.  FracFocus posts information regarding fracturing fluid composition on a well-by-well basis, using information voluntarily submitted by operators. 

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. 

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.

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 geology.com.  

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

Hydraulic Fracturing Litigation -- Defenses to "Abnormally Dangerous" Activity Claims

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.

Hydraulic Fracturing Litigation -- "Abnormally Dangerous" Activity Claims

On July 18, 2011, I made the first in a series of posts that will discuss hydraulic fracturing litigation.  I noted that plaintiffs have filed lawsuits in several states, alleging that their drinking water has been contaminated by hydraulic fracturing.  I also described the types of damages plaintiffs are alleging, and the types of relief they are seeking from courts. Finally, I listed the legal theories are "causes of action" that they typically are asserting.  One of those legal theories is sometimes described as being strict liability for harm resulting from an "abnormally dangerous" or "ultrahazardous" actvity.  Below, I provide a discussion of this legal theory, along with citations for those who desire citations to specific legal authority.

The common law has long recognized a theory of strict liability for defendants who engage in "ultrahazardous" or "abnormally dangerous" activities.  See Restatement (Second) Torts § 519.  The leading case generally is recognized as being the English case Rylands v. Fletcher, 3 H.L. 330 (1868).  In that case, the defendants were mill owners who constructed a large reservoir in which they stored water on their land.  The water broke through material used to plug an abandoned mine shaft and flooded the plaintiff's coal mine.  The lower courts held that the defendants were not negligent and that they could not be liable in the absence of negligence.  The House of Lords disagreed with the conclusion that the plaintiff had to prove negligence in order to recover, and held that a defendant can be strictly liable for an abnormal and inappropriate use of his property.

 If a particular type of activity is classified as "ultrahazardous" or "abnormally dangerous," a defendant can be held liable if he engages in that activity and thereby causes harm, even if the defendant was not negligent.  See Restatement (Second) Torts § 519.  Further, the defendant can be liable even if some intervening cause, such as the negligence of a third person or some force of nature, leads to the accident that results in harm.  See Restatement (Second) Torts § 523.

 To determine whether an activity is "abnormally dangerous," courts look to several factors.  Factors that weigh in favor of classifying an activity as abnormally dangerous include the following:  (1) the activity involves a high degree of risk; (2) any harm caused by the activity probably will be great harm, rather than minor harm; (3) it is impossible to eliminate risk associated with the activity even by the use of reasonable care; (4) the activity does not involve a matter of common usage; (5) the activity is inappropriate to the place where it is conducted; and (6) the risk of the activity outweighs value of the activity to the community.  See Restatement (Second) Torts § 520.  Classic examples of "abnormally dangerous" activity include blasting with explosives and pile driving. 

My next post in the series on hydraulic fracturing litigation will discuss defenses to "abnormally dangerous" activity claims.

Maryland Governor Announces Members of Commission to Study Shale Gas Production

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. 

West Virginia DEP to Draft Fracturing Regulations

West Virginia's acting Governor Earl Ray Tomblin has issued an Executive Order directing the West Virginia Department of Environmental Protection to use its emergency rule-making authority to draft regulations to govern hydraulic fracturing, pending the development of legislation.

Tomblin's Executive Order 4-11 mandates several requirements, including that:

  • Marcellus Shale drilling applicants seeking to drill within the boundaries of a municipality must file a public notice of intent to drill.     
  • Surface land uses that will disturb three or more acres must be certified by and constructed in accordance with plans certified by a registered professional engineer.    
  • Companies withdrawing over 210,000 gallons of water a month must file a water management plan with the DEP and adhere to certain specified standards. 
  • Before fracking begins, such companies must provide a list of additives they plan to use in the fracturing fluid, and after fracking is complete, a list of the additives actually used. 
  • When using water from a public stream, a company must identify the designated and existing uses of that stream.

Governor Tomblin's office announced the Executive Order on July 12, 2011.  In his weekly blog column, Governor Tomblin stated that use of hydraulic fracturing in development of the Marcellus Shale in West Virginia can create thousands of jobs and help recover an abundant source of energy, but that responsible environmental regulations are necessary.  It has been reported that both industry and environmental groups have reacted favorably to Governor Tomblin's Executive Order.

 Tomblin became acting Governor when his predecessor resigned to take a seat in the United States Senate.

Tuscaloosa Marine Shale Information

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.

New York DEC Recommends Lifting Moratorium on Hydraulic Fracturing

The New York Department of Environmental Conservation has recommended replacing New York's complete moratorium on high-volume hydraulic fracturing with regulations that would prohibit the process in certain areas and impose several new regulations on the process in other areas.  The current moratorium was put in place last year in order to give the DEC time to supplement and revise its 2009 draft of a Generic Environmental Impact Statement ("GEIS") regarding the use of hydraulic fracturing in shale gas development.   

The 2009 GEIS had recommended allowing hydraulic fracturing throughout New York, but many officials and citizens had expressed concern about allowing hydraulic fracturing within the watersheds that supply unfiltered water to New York City and Syracuse.  Hydraulic fracturing has become an issue primarily because the Marcellus Shale extends into New York, and that shale formation contains significant quantities of natural gas that can only be recovered through the use of hydraulic fracturing.  

The DEC's new, July 2011 draft GEIS recommends regulations that would 

  • ban hydraulic fracturing in the watersheds supplying New York City and Syracuse, and within 4000 feet of those watersheds 
  • ban drilling within primary aquifers
  • ban surface drilling within state-owned parks and other lands
  • ban surface drilling within any 100-year flood plan
  • place a moratorium on drilling within 2000 feet of any public drinking water supply well until regulators can evaluate three years of experience elsewhere with hydraulic fracturing
  • require disclosure of all fracking water additives to regulators, and provide for public disclosure of all additives that do not constitute trade secrets, and
  • require an intermediate well casing (well pipe) that would be placed between the outer "surface casing" and the inner "production casing" in order to provide additional protection against migration of gas at the well itself.

The DEC's recommendations also include measures for storm water control, regulation of water withdrawals, protection of air quality at drilling sites, and for the handling of "flowback," the water recovered after a hydraulic fracturing operation is completed.

DEC officials state that they believe their recommendations provide an appropriate balance between environmental concerns and the potential benefits of hydraulic fracturing, which include jobs and a decreased dependence on foreign sources of energy.  The DEC estimates that the restrictions it recommends would result in high volume hydraulic fracturing being allowed in about 80 percent of the portion of New York into which the Marcellus Shale extends. 

The DEC made various documents available on July 1, 2011, including an Executive Summary of the revised draft GEIS.  The full revised draft of the GEIS was made available yesterday.  The documents now available include: a time line regarding the GEIS, a fact sheet regarding what DEC believes it has learned from Pennsylvania's experiences with hydraulic fracturing, a press release regarding the DEC's recommendations, a list of the members of a new Hydraulic Fracturing Advisory Panel, a PowerPoint presentation from DEC's July 1, 2011 press conference, a simple diagram showing how an intermediate casing would help protect ground water, and the full draft GEIS, which can be download in its entirety or in portions from a web page that allows downloads by individual sections of the GEIS.  A video of the DEC's July 1, 2011 press conference regarding its recommendations also is available.

DEC plans to supplement its new GEIS next month with a section discussing socioeconomic and community effects of hydraulic fracturing.  The DEC then will begin a 60-day public comment period on the GEIS.

Governor Paterson imposed the current moratorium last year in his Executive Order No. 41, in which he also ordered the DEC to revise its 2009 draft GEIS regarding shale gas development.  DEC prepared the 2009 draft GEIS in order to address the potential for natural gas drilling in the Marcellus Shale, an activity that was not contemplated at the time the DEC prepared a 1992 GEIS relating to oil and gas drilling.

Paterson imposed the moratorium at the same time that he vetoed a bill that would have banned high volume hydraulic fracturing.  The moratorium applies to fracturing operations using large volumes of fracturing fluid, such as the fracturing operations typically employed with horizontal wells, but does not apply to hydraulic fracturing that uses relatively low volumes of fracturing fluid, such as operations to hydraulically fracture vertical wells.  Governor Cuomo continued the moratorium after he took office.

Tuscaloosa Marine Shale

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.

New Jersey legislature votes to ban hydraulic fracturing

By a lopsided margin, the New Jersey legislature has voted to ban hydraulic fracturing in the state.  The legislation, which passed by votes of 32 to 1 in the Senate and 56 to 11 in the House, would make New Jersey the first state in the U.S. to legislate a ban on the process.  Although little or no hydraulic fracturing has occurred in New Jersey, the Utica Shale lies beneath a portion of the northwestern part of the State, and companies have considered developing that resource.  The legislation now goes to Governor Chris Christie, and will become law if he signs the bill.

As previously reported in this blog, France recently became the first country to ban hydraulic fracturing.

France bans hydraulic fracturing

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." 

British Parliament issues report on hydraulic fracturing

The Energy and Climate Change Committee of the United Kingdom's House of Commons issued a report on hydraulic fracturing.  The report provides an interesting, foreign perspective on an issues that have become the subject of heated debate here in the United States.  The report includes a thorough discussion of several issues relating to hydraulic fracturing, as well as numerous specific recommendations and conclusions.  One of the Committee's conclusions is that hydraulic fracturing should be allowed to proceed in Britain:

On balance, we feel that there should not be a moratorium on the use of hydraulic fracturing in the exploitation of the UK's hydrocarbon resources, including unconventional resources such as shale gas."

The Committee analyzed both the benefits of hydraulic fracturing and the environmental concerns that have been raised.  The Committtee's report identified economic gains and decreased dependence on foreign sources of energy as being two of the benefits.  The Committee concluded that UK shale gas resources "could be considerable," though "it is unlikely that shale gas will be a 'game changer' in the UK to the same extent it has been in the U.S."  An interesting part of the report was a statement that Britain may have greater shale resources offshore than under land.

The report noted that hydraulic fracturing also has a potential environmental benefit because the process often is used to facilitate the production of natural gas, the cleanest burning of all fossil fuels ("shale gas" is simply a term for natural gas produced from shale).  The Committee stated:  "Shale gas could lead to a switch from coal to gas for electricity generation, thereby cutting carbon emissions, particularly projected emissions from developing countries." 

The report acknowledged that a countervailing concern raised by some environmentalists is that there are fugitive emissions (small leaks) of gas during the production and transport of shale gas.  Fugitive emissions are a concern because the main component of natural gas is methane, and methane (like carbon dioxide) is a greenhouse gas.  The report concluded, however, that fugitive emissions can be minimized through proper regulations.  The report also noted another concern -- that production of large quantities of shale gas might distract from efforts to develop renewable sources of energy.

But the main environmental concern that people express is a fear that hydraulic fracturing might harm the quality of underground sources of drinking water.  On this issue, the UK report reached conclusions similar to those stated previously in this blog.  The report noted that most shale formations are thousands of feet below drinking water aquifers, and that the fractures created by hydraulic fracturing are much shorter in length.  That leaves two other potential mechanisms for contamination to occur.  One would be for hydraulically-induced fractures to link with natural faults or fractures, leading to a pathway between the formation being fractured and a drinking water aquifer.  But most analysts in the United States think this is very unlikely, and the Committee seemed to agree. 

The general consensus is that, if contamination were to occur, it likely would be as a result of the other potential mechanism for contamination -- a well construction failure.  Most oil and gas wells, including both those that are hydraulically fractured and those that are not, are drilled to formations that are located deeper beneath the surface than drinking water aquifers are.  Oil or gas wells pass through the drinking water aquifer, and casing and cementing of the well are used to seal the drinking water aquifer from deeper formations.  Such casing and cementing has been done on millions of wells.  The UK report stated:

There is no evidence that the hydraulic fracturing process poses any risk to underground water aquifers provided that the well-casing is intact before the process commences.  Rather the risks of water contamination are due to issues of well integrity, and are no different than concerns encountered during the extraction of oil or gas from conventional reservoirs."

For that reason, the report concluded that care should be given to well construction standards and inspection.  The report expressed a belief that Britain's existing regulations for well construction are adequate.

Another issue of occasional concern in the United States is water supply.  Typically, a few million gallons of water are used in fracturing an oil or gas well drilled into a shale formation.  That amount is fairly modest compared to some other industrial and agricultural uses.  Nevertheless, this amount of water use can put a strain on supplies in areas that already are facing water shortages.  The UK report stated that water supply generally should not be a problem if fracturing is performed in Britain, but that fracturing "could challenge resources in regions already experiencing water stress."

The report also weighed-in on the issue of whether regulations should require that the composition of fracturing water be disclosed.  That has been a hot issue in the United States.  The UK report endorsed some reporting, but it is not clear whether the report meant to support the disclosure of the specific chemical compounds used.  The report said that well operators should report the volume of fracturing water used, as well as the "type" of chemicals used, and the concentrations.  In the debate within the United States about disclosure requirements, when people refer to the "type" of additive they often are referring to the functional category of an additive -- that is, whether the additive is a biocide, corrosion inhibitor, friction reducer, etc. -- rather than the identity of the specific chemical compound.  It is not immediately clear whether this is what the report meant, or whether it was advocating that specific chemical compounds be identified.

In addition, the report discussed the possibility of spills of fracturing fluid, and such localized effects as noise and traffic that can result from increased drilling activity, and how those concerns can be addressed.

The report contains two volumes.  The first contains the narrative report, plus a transcript of questions and answers from hearings.  The second contains written materials presented by various individuals and organizations, including environmental groups, trade groups, and companies.

EPA Selects Locations for Seven Hydraulic Fracturing Case Studies

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.

Michigan issues new hydraulic fracturing regulations

On May 25, 2011, Michigan's Department of Environmental Quality announced new regulations relating to "high volume" hydraulic fracturing.  The regulations will require oil and gas operators to report to DEQ the source they plan to use for water, and will require monitoring of the level in any wells within 1320 feet of an operator's proposed large volume withdrawal.  The regulations also will require operators to provide Michigan DEQ with Material Safety Data Sheets for the substances used in their fracturing.  Those MSDSs will be made available to the public.  In addition, operators will be required to provide Michigan DEQ with records relating to injection pressures, volumes of fracturing fluid, and volumes of flowback.

The new regulations define "high volume" fracturing as fracturing that uses more than 100,000 gallons of hydraulic fracturing fluid.  Michigan DEQ issued information explaining that oil and gas operators have used hydraulic fracturing in Michigan since the 1960s to produce natural gas from the Antrim Shale in the northern portion of the Michigan's Lower Peninsula.  Those wells are shallow, and typically operators only use about 50,000 gallons of water in the fracturing process.  This compares to typical water use of 4 to 5 million gallons per well in several deeper shales being hydraulically fractured in other parts of the country.  Michigan has implemented its new fracking laws in anticipation that oil and gas operators may begin drilling in Michigan to the Utica Shale, a deeper formation, and that operators would use much larger volumes of water in fracturing Utica wells than in fracturing Antrim wells.

Michigan DEQ officials have indicated that they do not believe the fracturing of underground formations itself is an issue to be concerned about, and that the important issues relate to well construction, water sourcing, and flowback disposal. 

Montana considers mandatory disclosure of frack water composition

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.

Texas enacts frack fluid disclosure requirement

Texas has enacted legislation requiring its Railroad Commission (the regulatory authority that regulates the oil and gas industry in Texas) to develop regulations for the mandatory disclosure of the composition of water used in hydraulic fracturing on a well-by-well basis.  The new law, which is reported to be the product of negotiations involving the oil and gas industry, environmental groups, and legislators, directs that this information be posted on the internet.  Companies can request that any particular chemical be exempted from disclosure if the identity of the chemical is a trade secret.  The initial decision whether to grant an exemption will be made by the Railroad Commission, but a decision by the Railroad Commission to grant an exemption can be appealed by the landowner on whose property the well is drilled, by an adjacent landowner, or a state agency other than the Railroad Commission.

The legislation gives the Railroad Commission until July 1, 2013 to finalize regulations, but Commission members have stated that they will begin the process of developing regulations soon, and one Commissioner has said he will push to finalize regulations a year early, by July 1, 2012. 

Texas' mandatory disclosure program is significant because Texas has drilling in several shale plays -- the Barnett, the Eagle Ford, the Permian Basin, and the Haynesville (the Haynesville Shale is mostly in Louisiana, but extends into East Texas).  Further, Texas has far more ongoing drilling than any other state.  The most recent rig count by Baker Hughes shows that 843 oil and gas drilling rigs are operating in Texas.  This is nearly half of the total of 1854 rigs operating in the entire United States, and is far more than the number operating in any of the three states with the next largest totals (170 are operating in Oklahoma; 166 are operating in Louisiana; and 161 are operating in North Dakota).

When Texas' regulations are put in place, the state will join Wyoming and Arkansas in requiring disclosure.  Both Wyoming and Arkansas enacted regulations last year that require disclosure of chemicals used in fracking water on a well-by-well basis.  Wyoming and Arkansas require disclosure of all chemicals to regulators, and provide that such information generally will be made available to the public.  But the regulations in both states allow companies to request that particular chemicals whose identities constitute trade secrets be exempt from disclosure to the public.  The Wyoming and Arkansas regulations were discussed in my blog post dated March 14, 2011.

In addition to mandatory disclosure programs, two groups of state regulators -- the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission -- have organized FracFocus, a website where several companies are voluntarily posting the composition of fracking water on a well-by-well basis.  Visitors to the website can search for wells near where they live (or in any other location), or by other criteria, such as well operator.  The website also contains other information on hydraulic fracturing.  FracFocus and certain company-specific voluntary disclosure initiatives were discussed in my blog post dated April 18, 2011.

Europe split on shale gas development

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.

Hydraulic Fracturing -- It's not just for gas.

Much of the news about hydraulic fracturing has concerned its use to produce natural gas from such shale plays as the Barnett, Haynesville, Fayetteville, and Marcellus.  But some shale formations contain oil, and hydraulic fracturing is playing a key role in producing oil from some of those shales, including the Bakken in North Dakota and Montana, and the Eagle Ford in south Texas.  Now, Amy Wold of The Advocate reports that Devon Energy is pursuing plans to use hydraulic fracturing to produce oil from the Tuscaloosa Marine Shale in East Feliciana Parish, not far from Baton Rouge.  A 1997 LSU study estimated that there are 7 billion barrels of oil in the shale, and Jim Welsh, Commissioner of the Louisiana Office of Conservation, is quoted as stating, "This will be Louisiana's Eagle Ford."  The use of hydraulic fracturing in shale formations already has helped the U.S. significantly increase its production of natural gas.  Now, hydraulic fracturing is starting to do the same for oil production.

Oil shale

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.

Haynesville: The Movie

I recently watched a documentary that I highly recommend -- Haynesville

The documentary's subject is the Haynesville Shale, an underground formation of sedimentary rock that stretches from northwest Louisiana into parts of east Texas.  In recent years, companies have drilled a large number of wells into the formation, utilizing horizontal drilling and hydraulic fracturing to produce natural gas. 

Haynesville follows three residents of northwest Louisiana to show how their lives have been affected by development of the Haynesville Shale.  The documentary takes a refreshingly balanced view.  Of the three individuals that the film follows, one is a community organizer who is very skeptical of energy companies and the potential adverse effects that development of the Haynesville Shale might have on the environment.  Another of the individuals followed in the film is very enthusiastic about development.  The third is a landowner who is an avid hunter and outdoorsman.  He is concerned about the effects that drilling operations might have on his land, but he eventually decides to grant a lease to allow drillng.

The director is Gregory Kallenberg, and the film has received excellent reviews, including a wonderful review from College Movie Review, whose website includes an interview with the director.  The film, which appeared on CNBC, has a website

Hydraulic fracturing: How effective are existing state regulations?

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: What are the 3 Big Benefits?

Hydraulic fracturing and horizontal drilling are old technologies, but they have been used with increasing frequency in recent years.  With the increased use, has come publicity and a great deal of public interest.  In a prior post, I explained what hydraulic fracturing is.  What are the benefits?  The big three are

  • jobs and tax revenue
  • improved national security, and
  • environmental benefits.

One of the greatest benefits is jobs.  One of several shale formations currently being developed is the Haynesville Shale in northwestern Louisiana and east Texas.  A recent article by Mark Schleifstein of the Times Picayune reports that a Louisiana State University economist estimates that drilling in the Haynesville Shale alone generated more than 57,000 jobs in 2010.  Others states with shale drilling also have seen job growth. 

Further, a March 2010 article by AP reports that personal income of residents in 10 states has rebounded to levels higher than before the start of the recent recession.  Four of the ten are states that have significant shale drilling -- Louisiana, Arkansas, Pennsylvania, and North Dakota -- and a few of the others are states that have some shale gas drilling.

 And the economic benefits have not been limited to individuals.  Local governments have benefitted.  Bruce Nolan recently reported on the effect of Haynesville activity in DeSoto Parish, which historically has been one of Louisiana's poorest parishes (Louisiana has parishes rather than counties).  DeSoto Parish now has some of the State's highest starting salaries for public school teachers.  And, despite the recent recession that has hit most of the country, DeSoto Parish is providing new buildings to 11 of the parish's 12 schools, and paying for construction of the new buildings in cash.  Further, the parish is paying cash for an animal shelter, the parish's first public park, and a convention center.  The small town of Logansport is getting a new branch library, with construction costs to be paid in cash. 

Other states that have shale gas activity also have seen job growth.  And officials in still more states, such as Ohio, are hoping to benefit from future shale drilling, as Ryan Dezember has reported.

 Shale gas (natural gas produced from shale) also can benefit our national security.  Unrest in countries that are major suppliers of crude oil demonstrate the risk of relying on oil imports.  Drilling and hydraulic fracturing of the Bakken Shale in North Dakota and Wyoming have produced a surge of production of domestic oil.  Several other shale formations, such as the Marcellus, Barnett, Haynesville, Woodford, and Fayetteville contain enough natural gas to supply our country's energy needs for many years.  According to the Energy Information Agency, this country has potential natural gas reserves sufficent to supply the country for 110 years (at 2009 rates of consumption), and a third of that supply is found in shale formations.  Further, the estimated amount of shale gas reserves is increasing rapidly as companies continue to explore. 

 Finally, shale gas production can benefit the environment.  Of all the fossil fuels, natural gas is the cleanest burning.  A report prepared for the Department of Energy states that, for an equivalent amount of energy production, the combustion of natural gas produces only half the carbon dioxide of coal and a third less than oil.  The same report notes that combustion of natural gas also produces less particulate matter, less sulfur dioxide, and less nitrogen oxides than does the combustion of other fossil fuels. 

These are tremendous benefits.  In prior posts, I've discussed some of the concerns people have raised about hydraulic fracturing.  Those concerns should be taken seriously and should be addressed, but we should not let those concerns stop hydraulic fracturing. 

Hydraulic fracturing: What is it?

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.