According to a Sierra Club press release, the DOGGR—the state agency charged with regulating all oil and gas well activity in California—acknowledges “it has not permitted or monitored the impacts of fracking and has never formally calculated the potential environmental and health effects of the practice, even as it continues to approve new permits for oil and gas wells.” The lawsuit asks the court to issue “[a]n injunction enjoining the DOGGR from the approval of any further permits for oil and gas wells where hydraulic fracturing may occur within the state of California unless and until it complies with the requirements of CEQA by considering, evaluating, and mitigating the environmental and public health impacts associated with hydraulic fracturing.”

Earthjustice attorney, George Torgun, who represents the environmental groups, stated

“Right now, the people of California don’t know where or when the drillers are fracking, what chemicals they are using, what pollutants they are releasing into the air and water, and what other risks they’re taking. That’s because the state hasn’t required them to disclose any information on fracking activities.”

Some other states, including Louisiana, have adopted regulations requiring companies engaged in fracking to report the chemicals used in their fracking fluids.

The study examined the potential for a variety of types of energy development projects to cause earthquakes.  The study began after the U.S. Congress directed the Department of Energy to request that the National Research Council "examine the scale, scope, and consequences of seismicity induced during fluid injection and withdrawal activities related to geothermal energy development, oil and gas development including shale gas recovery, and carbon capture and sequestration (CCS)."  The National Research Council stated:

Three major findings emerged from the study:

(1) the process of hydraulic fracturing a well as presently implemented for shale gas recovery does not pose a high risk for inducing felt seismic events;

(2) injection for disposal of waste water derived from energy technologies into the  subsurface does pose some risk for induced seismic activity, but very few events have been documented over the past several decades relative to the large number of disposal wells in operation; and

(3) CCS, due to the large net volumes of injected fluids, may have potential for inducing larger seismic events."

The report noted that, "[a]lthough induced seismic events have not resulted in a loss of life or major damage in the United States, their effects have been felt locally, and they raise some concern."  The report suggested that the largest number of induced seismic events related to the energy industry arise from geothermal operations.  According to the report, 300 to 400 seismic events large enough to be felt are likely caused each year in the U.S. by so-called "vapor-dominated" geothermal operations, which seek to recover geothermal energy that is contained primarily in steam found in underground rock formations.  Another 10 to 40 seismic events large enough to be felt are caused each year in the U.S. by "liquid-dominated" geothermal operations, which seek to recover  geothermal energy found in hot water located in underground formations, and 2 to 10 seismic events large enough to be felt likely are caused by geothermal operations that seek to recover geothermal energy found in hot dry rocks underground.

In contrast, hydraulic fracturing is "suspected, but not confirmed" as the cause of one seismic event large enough to be felt in the U.S. (in Oklahoma) during the more than 60 years that hydraulic fracturing has been used.  And "only one case of felt seismicity" caused by hydraulic fracturing has been "confirmed" anywhere in the world (in Great Britain).  The report concluded that "[t]he very low number of felt [seismic] events relative to the large number of hydraulically fractured wells for shale gas is likely due to the short duration of injection of fluids and the limited fluid volumes used in a small spatial area."

Some mainstream media reports have attempted to link additional seismic events to fracturing, but government authorities and scientists have concluded that those events were either natural or induced by underground waste disposal activities, rather than hydraulic fracturing.  The report stated that "[r]educing injection volumes, rates, and pressures have been successful in decreasing rates of seismicity associated with waste water injection."

Other oil and gas practices are suspected of causing a handful of induced seismic events according to the report.  For example, the report stated that secondary recovery operations, which the oil and gas industry has been performed at approximately 108,000  wells, is suspected of having induced seismic activity at 18 locations, and hydrocarbon withdrawals or suspected of having induced seismic activity at 20 locations. 

The report also noted that various human activities other than those associated with fluid injections and withdrawals also are suspected of having induced seismic events.  These activities include impounding large reservoirs behind dams, using controlled explosions related to mining, and conducting underground nuclear testing.

The report recommended that "best practices" be developed to minimize the chance of induced seismic activity from each type of energy activity that involves fluid injection or withdrawal.  The report stated that the basic mechanism by which human activity can caused induced seismic activity is well understood, and is caused either by changes in the pressure of fluids found in the pore spaces of underground formations, or changes in subsurface stresses.  But there are some gaps in knowledge, and modeling and predicting induced seismic activity is difficult because of the complexity of underground rock formations and the lack of knowledge about local subterranean stresses.  The report recommed that additional research be done. 

Although the report stated that carbon sequestration and capture has the potential for inducing larger seismic events than those typically caused by other human activities, the report also noted that definitive conclusions regarding the likelihood for CCS activities to induce seismic activity are difficult to make because of the lack of experience with large scale CCS projects.  

A copy of the report is available from National Academies Press.

What Accounts for the Large Difference Between the Estimates? 

The most dramatic difference between the API/ANGA estimates and EPA estimates relate to emissions during liquids unloading (a process in which liquid is removed from a natural gas wellbore so that the liquid does not obstruct the flow of gas).  API/ANGA's survey showed that a lower percentage of wells vent to the atmosphere than the EPA assumed and that the wells that vent do so for a shorter time than the EPA assumed.  The API/ANGA study estimates that emissions during liquids unloading are 86% lower than the EPA estimates.  API/ANGA's study also found that the total emissions during the re-fracturing of wells is much lower than the EPA estimated ─ 72% lower.  The main explanation for the difference in estimates is that API/ANGA found that the number of wells that are re-fractured is much lower than the EPA estimated. 

Why Do the Rates of Emission of Natural Gas Matter? 

Emissions of natural gas are undesirable because volatile organic compounds ("VOCs") can contribute to ground level ozone formation and because methane (the principal component of natural gas) is a greenhouse gas.  The EPA has devoted increased attention to emissions from the oil and gas industry.  For example, the EPA recently published new regulations that aim to decrease emissions of natural gas and VOCs during the production, storage, and transport of oil and gas.  Opponents of the oil and gas industry, and opponents of hydraulic fracturing, also have devoted increased attention to such emissions.

Links 

• Fact Sheet on API/ANGA study 
• API/ANGA study (54 pages) 
• API press release regarding study  
• ANGA press release regarding study
• Oil & Gas Law Brief post regarding EPA's new air regulations.

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.

The regulations require operators to disclose on a well-by-well basis

• the name of the operator
• the type of base fluid used (this is typically water, but can be some other substance)
• the trade name, supplier, and general purpose of each substance intentionally added to the base fluid
• the identity, Chemical Abstracts Service (CAS) number, and maximum concentration for each ingredient in each substance intentionally added to the fracturing fluid
• the API number of the well (an identification number unique to each well)
• the longitude and latitude of the surface location of the well, and
• the dates on which hydraulic fracturing operations began and ended.

The information must be disclosed within 60 days of the operator completing hydraulic fracturing operations. The operator must either post the information on the FracFocus website or send the information directly to the Oklahoma Corporation Commission, the agency that regulates the oil and gas industry in Oklahoma. If the operator submits the information to the Corporation Commission, the Commission will post the information on FracFocus. 

FracFocus is a website that has become a central place for posting the composition of hydraulic fracturing fluids.  Some companies voluntarily post information there.  In addition, several of the states that have enacted mandatory disclosure requirements direct companies to make their required disclosures by posting information on FracFcous, where it is readily accessible to the public.

Under Oklahoma's new regulations, a producer need not disclose information that the producer contends meets the standards to constitute a "trade secret" under the Uniform Trade Secrets Act, 78 Okla. St. Ann. §§ 85-94. In such circumstances, the operator must still disclose the chemical family to which a compound belongs. Also, the Corporation Commission can require a written explanation of the trade secret claim.

The Corporation Commission also has made available a document that includes copies of public comments regarding the proposed drafts of the regulations, the Commission's responses to the comments, and the changes made to the drafts of the regulations.

Background of the Cove Point Terminal

Dominion's Cove Point LNG terminal was originally owned by Columbia Gas, which constructed the terminal as an LNG import terminal in the 1970s.  Columbia only operated the facility as an import terminal for a couple of years, but in the 1990s it added liquefaction capability at the facility for use in providing "peaking service."  This involves liquefying natural gas and storing it during periods of low demand, then regasifying and selling it during periods of peak use. 

Dominion acquired the facility in 2002 and applied to the Federal Energy Regulatory Commission for authority to expand the facility and use it again for LNG imports.  In 2005, Dominion entered an agreement with the Sierra Club and Maryland Conservation Council, in which those environmental organizations agreed not to oppose Dominion's expansion of the terminal in return for Dominion's agreement regarding the protection of certain other nearby areas.  Since then, Dominion has used the facility for LNG imports.

What led to the current dispute?

Up until the last few years, there were projections that the United States would remain dependent on natural gas imports, including LNG imports, into the foreseeable future.  But domestic production of natural has increased dramatically in the last few years, in large part because of the use of horizontal drilling and hydraulic fracturing to produce natural gas from shale formations.  That has led to decreased imports, and to such a plentiful domestic supply of natural gas that companies are planning to export natural gas.  Dominion applied to the Department of Energy for permission to export natural gas and received preliminary approval to do so last October.

But on April 26, 2012, the Sierra Club sent a letter to Dominion, demanding that it cease plans to export natural gas from Cove Point.  The same day, the Sierra Club issued a press release declaring its opposition to Dominion's export plans.  The Sierra Club contends that the 2005 agreement prevents Dominion from expanding the terminal or from using it as an export facility.  Thus, contends the Sierra Club, Dominion cannot export LNG from Cove Point without the Sierra Club's consent.  Further, the Sierra Club states that it will not give that consent.  In part, the Sierra Club says it objects to expanding the footprint of the terminal, which Dominion plans to do by building additional liquefaction capacity, which would be needed in order to operate the terminal as an export facility.  But the Sierra Club stated that Dominion's operation of the terminal as an export facility would be "unacceptable ... even if Dominion confined its new construction to the existing plant site."  Why?  Because the export of natural gas would encourage more natural gas drilling and the use of hydraulic fracturing, which the Sierra Club opposes.

Dominion's Contentions and its Lawsuit

Dominion Cove Point LNG, L.P. filed suit in the Circuit Court for Calvert County against the Sierra Club, the Maryland Chapter of the Sierra Club, and the Maryland Conservation Council.  Dominion disputes the Sierra Club's contention that the 2005 agreement limits Dominion to using the Cove Point terminal for LNG imports.  Further, contends Dominion, the Sierra Club's opposition to Dominion's export of LNG from Cove Point has very little to do with concern about LNG exports, construction activity at Cove Point, or an enlarged footprint for the terminal.  Instead, the Sierra Club's primary reason for opposing the export of LNG is that the Sierra Club opposes drilling for natural gas and the use of hydraulic fracturing, and the increased availability of LNG export facilities will encourage natural gas drilling.  To support its point, Dominion points to the Sierra Club's "Beyond Natural Gas Initiative."  Further, both the Sierra Club's April 26 press release and its April 26 letter to Dominion give prominent attention to the Sierra Club's opposition to hydraulic fracturing and natural gas drilling, even though neither of those are directly at issue in Dominion's proposal.  Dominion's lawsuit seeks a declaratory judgment that the 2005 agreement does not prevent it from building and operating LNG export facilities at its Cove Point terminal. 

In addition to arguing that the 2005 agreement does not prevent such use, Dominion points out that the proposed project would result in an additional $40 million per year in property tax revenue for Calvert County, 70 to 100 permanent jobs in Calvert County, and 2500 to 3100 construction jobs.

Dominion would like to begin construction in 2014, with a schedule that would call for putting the proposed export facility into service in 2017, pending necessary regulatory approvals and the negotiation of terminal service agreements.

Why is this Important Beyond Calvert County, Maryland?

The resolution of Dominion's lawsuit will turn on the court's interpretation of the language in the 2005 agreement, and the court's interpretation of that language is not likely to have a direct effect on any other disputes.  The importance of this dispute is that it shows the Sierra Club's determination to oppose projects that will encourage ─ even indirectly ─ greater drilling for natural gas and use of hydraulic fracturing.  Natural gas is the cleanest burning of all fossil fuels, and there have been projections that the plentiful supply of natural gas will contribute to an increased use of gas and a decreased use of coal for generating electricity.  Will the Sierra Club oppose increased drilling for natural gas even if less drilling mean more coal use in the U.S.?  Will the Sierra Club continue to oppose natural gas exports if less exports would mean more coal use abroad?

Resources

• Dominion's Lawsuit 
• Letter from Sierra Club to Dominion 
• Sierra Club's Press Release
• Dominion's Press Release
• 2005 agreement between Dominion and the Sierra Club
• Dominion Cove Point LNG website
• Maryland Sierra Club website 
• Dominion's main website
• Sierra Club's "Beyond Natural Gas Initiative"

Under Loveland's current zoning, oil and gas operations are prohibited in all of the City's zoning districts except "Industrial" and "Developing Resource."  Further, even in those areas, oil and gas activity is not allowed unless the City approves the proposed activity after the proposal undergoes a special review.   The Centerra area of Loveland is not governed by one of the City's normal zoning districts, and instead certain "Millennium Planned Unit Development" restrictions apply.  Although those restrictions do not expressly prohibit oil and gas activity, such activities are not currently allowed in the area.  The City Manager stated that the moratorium will give the City time to consider whether it wishes to enact zoning ordinances that place even greater restrictions on oil and gas activity than those that exist now.

The moratorium was enacted as an "emergency ordinance" because the Council wanted to enact it Tuesday night, which also was the night that the ordinance was first proposed.  Under the Council's normal rules of procedure, a proposed ordinance generally must be introduced at one meeting and enacted at a subsequent meeting.  But an "emergency ordinance" can be passed at the same meeting at which it is proposed.

The materials for last week's meeting included a memorandum from Loveland's City Manager, who stated that a number of citizens requested during the May 1, 2012 Council meeting that the Council implement a moratorium.

A number of other Colorado communities, including Longmont, Colorado Springs, El Paso County, Erie, and Boulder County.  In addition, Fort Collins is considering a moratorium.

The ordinance does not revoke any existing land use permits.  Thus, if someone already has an approved land use permit for oil and gas activity, that activity apparently will be allowed to proceed.

The legislation also directs Vermont's Secretary of Natural Resources to submit a report by January 15, 2015 recommending how hydraulic fracturing should be regulated in the event the ban is rescinded.  The report is to include discussion relating to how hydraulic fracturing wastewater should be treated, how water withdrawals for hydraulic fracturing can be managed, and how traffic issues should be addressed.  The legislation requires the Secretary of Natural Resources to provide a second report by January 15, 2016.  The second report is supposed to discuss the environmental impact of hydraulic fracturing and its potential effects on human health, summarize relevant peer‑reviewed studies, and make a recommendation regarding whether hydraulic fracturing should be prohibited.

The website for the Vermont State Legislature can be used to view the original and interim drafts of the legislation as it made its way through the legislature.  Governor Shumlin's official website has a video of a statement the Governor made regarding the legislation.

To date, there has not been any shale play activity in Vermont, though some experts state that a shale formation may extend beneath one corner of the state.  Indeed, Vermont has never had much oil and gas activity of any kind, whether conventional or unconventional.  Baker‑Hughes rig counts show that there are no oil or gas drilling rigs currently operating anywhere in the state, and that it has been years since any rotary rig drilled for oil or gas in Vermont.  The Vermont Geological Survey states that there never has been a productive oil or gas well in Vermont and that it has been about 28 years since the last dry hole was drilled. 

In its judgment, the court noted that the Colorado Oil and Gas Conservation Commission had conducted an investigation and concluded that the Strudleys' water supply had not been affected by oil and gas operations.  Further, the plaintiffs' own environmental expert could go no further than to state that the results of his analyses of the plaintiffs' water supply "could be consistent with contamination from gas well chemicals or production waters."  He could not state an opinion that the defendants' activities had actually caused any contamination.

The court also noted that the Strudleys' medical expert reached "no opinion as to whether exposure was a contributing factor to Plaintiffs' alleged injury or illness."  The medical expert could only state that the plaintiffs' symptoms coincided in time with the defendants' wells being brought into production. 

The court's judgment dismissing the case was signed last week, on May 9, 2012.

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.

Why does the guidance focus on the use of "diesel" in fracturing?  The SDWA generally prohibits any underground injection that is not authorized by permit or some other rule.  But under the SDWA, hydraulic fracturing is not classified as an "underground injection," unless diesel fuel is included in the fracturing fluid.  That is why the guidance specifically relates to hydraulic fracturing operations in which diesel is used in the fracturing fluid.

Why was a guidance document needed in the first place?  In the past, the EPA has not required SDWA permits for fracturing, even when diesel is included in the fracturing fluid, but the EPA announced in 2010 that companies would have to obtain SDWA permits before using fracturing fluid containing diesel.  Because the EPA has not previously required permits, both companies and regulators were uncertain what standards would be used in evaluating permits.  Also, because the SDWA does not define "diesel," there was uncertainty regarding what substances would be considered "diesel" for purposes of SDWA permitting requirements.  The guidance document is the EPA's attempt to provide clarification.

Where does the guidance apply?  The guidance will apply only in states where EPA administers the SDWA program.  Many states have "primacy," meaning that those states have their own SDWA regulatory programs that meet certain federal standards, and those states have been delegated the responsibility to administer SDWA enforcement within the state.  The guidance document will not apply in the states that have primacy, but those states may adopt the  new guidance standards if they choose.

The draft regulations also include provisions that BLM says will improve assurances of well-bore integrity, in order to prevent fluids from escaping the well, and confirm that operators have a plan in place to properly handle and fracturing flowback water.  Once in place, the regulations will apply to a large number of wells.  BLM estimates that about 3400 wells are hydraulically fractured on federal lands or Indian lands each year, about 90% of the total number of wells drilled on those lands. 

The regulations will require companies to obtain BLM's approval of any hydraulic fracturing operation prior to conducting the operation.  The well operator can seek approval for fracturing at the same time that the operator submits an application for a permit to drill, or the operator can seek approval later.  So that BLM will have sufficient information to evaluate  requests for authority to conduct hydraulic fracturing, the draft rules would require the operator to give BLM a report that includes:

• a geological description of the formation that would be hydraulically fractured, as well as the depths of the top and bottom of the formation   
• the source location for the water that would be used in fracturing 
• the type of proppants to be used in the fracturing   
• the anticipated pressures to be used in the fracturing operation     
• an estimate of the total volume of fracturing fluid to be used    
• an estimate or calculation of the anticipated fracture length           
•  the estimated volume and composition of flowback water that would be recovered after fracturing    
• the methods the operator intends to use to manage flowback (including information regarding any pits or ponds to be used), and
• the operator's plans for eventual disposal or reuse of the flowback.   

The operator also will be required to submit a cement bond log to the BLM prior to fracturing in order to ensure mechanical integrity of the wellbore.  The purpose of this log is to verify that there are no voids in the cement that is supposed to fill the annulus between the well's casing and the well's outer wall, thereby providing a seal to prevent vertical migration of fluids through the annulus.  In addition, the operator will be required to perform a pressure test of the wellbore prior to fracturing, to ensure that it can withstand the maximum pressures expected during fracturing.

During fracturing, the operator would be required to continuously monitor the annulus pressure (an unexpected change in the pressure could be an early indicator of a problem with well integrity).  The draft regulations would require operators to store the flowback water recovered from the fracturing operation in tanks or lined pits to minimize the chance for an unintentional release.  After the fracturing operation is complete, the operator must provide BLM with a report that includes such information as the actual amount of water used and recovered, and a discussion of any ways in which the fracturing operation deviated from what was expected.  

The post-fracturing report also must identify each additive used in the fracturing fluid by trade name, additive purpose (such as biocide, corrosion inhibitor, etc.), and the Chemical Abstracts Service Registry Number (which provides a unique identification for each known chemical compound).  The information provided to BLM will be made public unless the operator submits with the report a claim that a particular additive constitutes a trade secret that is protected against disclosure by some existing federal law. 

An operator that makes a trade secret claim must identify the federal law that the operator claims provides the protection against disclosure.  If a operator makes such a claim, the BLM will not publicly disclose the identity of the additive unless the BLM determines that federal law does not provide the protection the operator claims.  If the BLM makes such a determination, it will give the operator at least ten days notice before publicly disclosing the identity of the additive for which the BLM determined the trade secret claim was invalid. 

BLM states that it plans to make the publicly-disclosed information available on the internet.  It is evaluating the possibility of making FracFocus the platform for such disclosures.  FracFocus began as a website for well-by-well disclosures of fracturing water composition by operators who were willing to make voluntary disclosures.  But several states that have adopted requirements that operators disclose the composition of fracturing fluid have directed operators to post the information on FracFocus, which has now become a central source for such disclosures.

The draft regulations will soon be published in the Federal Register, after which there will be a 60-day public comment period on the draft. 

In addition to the draft regulations, the Department of Interior issued a press release regarding the draft and BLM's analysis of the likely economic impact of the proposed regulations.

The province also has an information page on its website regarding hydraulic fracturing.

The requirement for "reduced emissions completions" relates to the flowback portion of hydraulic fracturing operations, when the water that is used to fracture the underground formation is recovered from the well, prior to the well being put into production.  When it flows back to the surface to be recovered, that water is accompanied by natural gas.  Some companies vent that natural gas.  The new rules will require companies to conduct "reduced emissions completions" in which they recover that natural gas whenever recovery is feasible.  The new rules will require that companies send the natural gas to a flare for combustion whenever recovery is not feasible.  Either way — whether the natural gas is recovered or flared — the emissions of VOCs will be lower than if the natural gas were vented.    

A couple of states already require reduced emissions completions, but industry representatives expressed concern about immediate implementation of a nationwide rule.  Specifically, industry has stated that the type of equipment used to conduct reduced emissions completions does not exist in sufficient quantity for all the wells that are being hydraulically fractured nationwide, and that immediate implementation of a nationwide rule would bring drilling operations to a halt in some places.  Industry urged that the effective date of the reduced emissions requirement be delayed so that a sufficient quantity of the necessary equipment can be built. 

In response to that concern, the EPA is delaying until January 1, 2015 the requirement that companies recovery the natural gas whenever feasible.  In the meantime, however, companies will be required to flare the natural gas if they do not recover it.  Thus, the emissions of VOCs still will be reduced.  The requirement that companies flare the natural gas (if they do not recover it), along with portions of the new rules that apply to aspects of oil and gas activity other than hydraulic fracturing, will go into effect 60 days after the rules are published in the Federal Register.  That publication should occur soon.

For additional, information, see:

• Text of new rules (588 pages)
• Summary of new rules
• Summary of changes made in rules since publication of original draft rules 
• Summary of requirements relating to natural gas well sites  
• Summary of requirements relating to natural gas compressor stations  
• Summary of requirement relating to natural gas processing plants  
• Summary of requirements relating to natural gas gathering and boosting stations 
• Summary of requirements for equipment used in oil production
• Oil & Gas Law Brief post dated August 10, 2011, discussing proposed rules. 

An earlier report likewise concluded that the earthquakes likely were caused by hydraulic fracturing operations conducted by Cuadrilla.  That earlier report concluded that "an unusual combination of factors" had made it possible for hydraulic fracturing to induce earthquakes, and that the combination of factors was unlikely to occur again.  The unusual circumstances included the fact that the fracturing operations were being conducted in a location that led to injections being made directly into a fault zone. 

The newly-released report, dated April 2012, states that "it is not possible to state categoriclly that no further earthquakes will be experienced" if a "nearby" well is fractured beause knowledge about the underground fault system in that area is "poor."  The new report stated, however, that the lack of information regarding faulting in the area possibly could be corrected by using 3-D seismic mapping.  The new report also concluded that it is unlikely that any additional earthquakes large enough to cause structural damage will occur even if fracturing is resumed in the area.

The conclusion that it took a set of highly unusual circumstances for fracturing to cause the earthquakes seems to be confirmed by U.S. experience.  In the United States, hundreds of thousands of fracturing jobs have been performed and rarely have they been suspected of causing seismic activity.  On several occasions, it has been suspected that the operation of wastewater disposal wells has induced seismic activity in the U.S., but wastewater disposal wells are operated different than hydraulically fractured oil and gas wells.  Some of the most famous earthquakes that are suspected of having been caused by human activity occurred near Denver in the 1960s, where the Army was using an injection disposal well to discard wastewater from the Rocky Mountain Arsenal.

For additional information from Britain, see the British government's webpage that invites comments on the new report and provides background factsheets on shale gas and induced seismicity.  For prior blog posts on this issue, see the Oil & Gas Law Brief posts dated April 16, 2012, March 13, 2012, and January 9, 2012.

STRONGER's report, published in February 2012, stated that "the Arkansas program is well managed and professional and generally meets the 2010 Hydraulic Fracturing Guidelines" published by STRONGER.  The report identified the following strengths of the Arkansas program:

• Updated Rules -- "Arkansas was among the first states in the nation to establish a system for the public disclosure of chemicals used in hydraulic fracturing operations." 
• Well Water Complaint Protocol -- "The [Arkansas Oil and Gas Commission] has developed a water well complaint protocol that guides staff ... .  This well developed guidance document could serve as an example to other states." 
• Website -- "The AOGC web site contains a wealth of information on hydraulic fracturing of gas wells in Arkansas."  Further, "[t]he web site is user friendly and educational."

The STRONGER team that reviewed the Arkansas program also made 3 specific recommendation for improving the program: (1) amend its regulations to require operators to provide notification to regulators prior to the start of fracturing so that regulators can monitor hydraulic fracturing operations; (2) secure permanent funding for four field inspector positions that are now supported with temporary (two year) funding; and (3) secure additional funding to increase field staff.

The STRONGER review included the submission of written questions, as well as site visits to the Arkansas Oil and Gas Commission.  The STRONGER review team consisted of seven members, including representatives from industry, environmental interests, and regulators from other states.

STRONGER's website also contains reports that review the oil and gas regulations of several other states.

The possibility that humans are causing seismic activity has generated significant attention recently, in part because hydraulic fracturing is a popular news topic and many media sources erroneously have reported that scientists believe hydraulic fracturing is to blame for an increase in earthquakes. 

The latest series of erroneous reports began circulating after publication of the abstract of a paper that a USGS scientist will present this week at a meeting of the Seismological Society of America.  Although the abstract never mentions hydraulic fracturing, and instead plainly states that earthquakes may be linked to "waste water injection wells," a Department of Interior official felt compelled to issue a statement after a series of inaccurate media reports erroneously indicated that the USGS had linked earthquakes and hydraulic fracturing.  

As the official described it, "a number of news articles started popping up," and "[u]nfortunately ... the accuracy of the news reports varied greatly."  The official explained that USGS scientists have found the U.S. mid-continent area has seen an increase in seismic activity, and that the increase is "likely" caused by human activity, but:

USGS's studies do not indicate that hydraulic fracturing, commonly known as "fracking," causes the increased rate of earthquakes.  USGS's scientists have found, however, that at some locations the increase in seismicity coincides with the injection of wastewater in deep disposal wells."

And to make sure there was no confusion this time, he repeated himself, stating:

We also find that there is no evidence to suggest that hydraulic fracturing itself is the cause of the increased rate of earthquakes."

The statement notes that wastewater is a by-product of oil and gas activity.  Operators often dispose of that water in wastewater injection wells, but other types of wastewater also are discarded in injection disposal wells.  Indeed, one of the earliest examples of earthquakes apparently being caused by the operation of an injection well occurred in the 1960s near Denver, where the U.S. Army was disposing of wastewater at the Rocky Mountain Arsenal. 

Further, even within the oil and gas industry, the use of injection disposal wells is not limited to use in servicing oil or gas wells that have been hydraulically fractured.  Even for a conventional oil or gas well that is not hydraulically fractured, wastewater typically is produced as a by-product because the liquid that is produced from the well contains some water, and is not exclusively oil and gas.  This co-production of water and oil or gas occurs because the underground formations that contain oil and gas also contain water, and some of that water often is produced along with the oil and gas.  The most common way to dispose of such "produced water" is by underground injection. 

If a well is hydraulically fractured, there is an additional source of wastewater.  Much of the water that is used to fracture the well is recovered as "flowback" water before the well is put into production.  Flowback water also is often discarded by use of underground injection wells.  

In discussing the increase in earthquakes in the mid-continent area, the Department of Interior official stated: "These earthquakes are fairly small -- large enough to have been felt by many people, yet small enough to rarely have caused damage."

One of the most recent earthquakes that is believed to have been caused by operation of an injection disposal well occurred on December 31, 2011 near Youngstown, Ohio.  In the past, authorities have suspected that injection disposal wells have caused earthquakes in Arkansas, Colorado, Oklahoma, and Texas.

The USGS website contains a page with answers to frequently asked questions on this subject.

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. 

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.