Oil and Gas Lawyer Blog

Gasland is a film documentary about the dangers caused by hydraulic fracturing of gas wells being drilled in shale plays across the U.S. It won a Special Jury Prize at the Sundance Film Festival this year. It was filmed by Josh Fox, whose family owns land in Pennsylvania that is in the Marcellus Shale Play. Gasland is now being screened across the country.

Josh Fox was recently interviewed about his film on the PBS program NOW. The film asserts that frac'ing of wells has caused underground aquifers to be charged with methane in Pennsylvania and Colorado and poses severe risks of contamination to the water supply. Josh Fox notes that hydraulic fracturing is exempt from federal regulation, and he advocates for passage of the FRAC Act now before Congress that would give the EPA jurisdiction over hydraulic fracturing.

The comments about the NOW story posted on its website evidence the growing controversy over frac'ing.

 

Continue reading "Movie 'Gasland' Stirs More Controversy About Hydraulic Fracturing" »

Newfield Exploration has reported that it is drilling horizontal wells with "super extended laterals" in the Woodford Shale in Oklahoma -- wells with laterals exceeding 5,000 feet. Newfield has so far drilled 14 super-extended lateral wells, with an average length of 9,000 feet. Those wells had an average gross initial production rate of approximately 9 MMcfe/day.

ConocoPhillips reported that it has completed the drilling of four horizontal wells in the Eagle Ford shale play, in its "liquids-rich" core. The first of these wells was put on production in March and flowed at an initial rate of 3.8 mmcf/day and 1,200 barrels/day of condensate.

All of the new shale gas production continues to put downward pressure on gas prices. Natural gas futures for June delivery fell 36.8 cents, or 8.5 percent on Thursday, April 29 on NYMEX. So far this year, natural gas futures have fallen 29 percent. The Energy Information Administration reported that the supply of gas in storage increased  by 83 Bcf for the week ended April 30. Gas in storage is 315 Bcf above the 5-year average.

The Park Foundation has submitted a resolution for consideration at ExxonMobil's annual meeting urging ExxonMobil to prepare a report on the environmental impact of fracturing operations and what can be done to reduce or eliminate environmental hazards caused by hydraulic fracturing.  The proposal, and ExxonMobil's response, provide a good summary of the state of the debate in the U.S. over potential environmental impacts of hydraulic fracturing. I have reproduced the entire statement from Exxon's proxy statement below.

Continue reading "ExxonMobil Proxy Statement Addresses Chemicals Used in Hydraulic Fracturing" »

An interesting article by Joe Carroll of Bloomberg News explores the problems faced by South Texas Ranchers seeking to require cleanup of old oilfield contamination. These problems are widespread in Texas and in my opinion the Texas Railroad Commission is ill equipped to address the problems.

An interesting case has recently been filed in Louisiana challenging the authority of the Louisiana Department of Conservation to approve pooled units containing multiple wells. In Gatti et al. vs. State of Louisiana, et al., Number 589350, Division 23, filed in the 19th Judicial District Court in East Baton Rouge Parish, the plaintiffs sued the State Department of Conservation and several operators in the Haynesville field, including Chesapake, Encana, Exco, Conoco Phillips, Petrohawk, SWEPI, EOG, Questar, Forest and XTO, claiming that the Department of Conservation was routinely allowing the drilling of "alternate unit wells" on previously established units, in violation of Louisiana law. A copy of the petition may be found here.  Gatti v. St of Louisiana.pdf.

Louisiana has a forced-pooling statute that allows an operator to propose to the Department of Conservation a unit for a well which, if approved, forces all mineral owners in the unit to pool their interests for the drilling and production of that well. According to the plaintiffs, this statute only authorizes the Department to approve units large enough to cover an area drained by one well. The practice in Lousiana for the Cotton Valley and Haynesville fields is to obtain orders for 640-acre units, and later obtain approval to drill additoinal "alternate unit wells" on those units. The suit contends that this practice is unfair to the owners of minerals and royalties in the unit, and violates state law. The suit seeks certification of a class action on behalf of all owners of mineral rights in Haynesville Zone in Louisiana. It seeks a declaration that the Department has no authority to establish a unit having an area in excess of the area drainable by one well, and that any such unit is "null and void." The suit also seeks unspecified damages against the defendant companies.

An interesting article describing the history of forced pooling in Louisiana and arguing that multiple-well units are illegal may be found at fairdrilling.com.

I have written previously about the proceeding before the Texas Railroad Commission for adoption of field rules for the Carthage (Haynesville Shale) Field. In that proceeding, the applicants sought and obtained field rules establishing a standard proration unit of 640 acres for wells in the field, with "optional" 40-acre units. The examiners who heard the evidence opined that Devon had produced no evidence that a well in the field could drain 640 acres, and they recommended a 320-acre standard unit, but the Commissioners overruled them and agreed to Devon's request for 640-acre units.

It appears that in both Lousiana and Texas the regulators are going along with the fiction advocated by operators that wells in the Haynesville should be developed with 640-acre units, despite the fact that everyone knows the wells will in fact be drilled with 160 or 80-acre spacing. Everyone understands that this fiction is intended to accommodate the desires of the operators to construct larger units in order to (i) have more flexibility in how they space their wells and (ii) hold more acreage with a single well. I have sympathy with the first objective, but not with the second. It is impossible to drill wells with horizontal legs of 5,000 feet or more unless fairly large units are created. Conversely, it is unfair to the mineral owners in a large unit for their leases to be held by production from a single well in the unit where several wells are necessary to fully develop the reservoir under their lands.

The Bureau of Land Management has signed a settlement agreement in which it agreed to "suspend" oil and gas leases covering BLM lands in Montana until it has completed a review of the effect of oil and gas development on greenhouse gas emissions.

The settlement was entered in Montana Environmental Information Center, et al. v. United States Bureau of Land Management, Case No. 08-178-M-DWM, in the U.S. District Court for the District of Montana, Missoula Division, on March 11, 2010. The case was brought by citizens groups who contended that federal law required the BLM to consider the cumulative impacts of oil and gas development on the environment, and specifically the greenhouse gas emissions caused by oil and gas well drilling and production, before granting oil and gas leases on lands in Montana.

The plaintiffs' petition contains some interesting facts:

The State of Montana published a Greenhouse Gas Emissions Inventory and Reference Case Projections 1990-2020G, in 2007; it estimated that oil and gas operations in Montana released 4.7 million metric tons of CO2 or its equivalent in 2005, more than 12% of the state's total GHG emissions.

According to the Inventory of U.S. GHG Gases and Sink: 1990-2006, by the Environmental Protection Agency, oil and gas systems are the largest human-made source of methane emissions and account for 24% of methane emissions in the U.S. - 2% of the U.S.'s total GHG emissions. (Methane - natural gas - has 21 times the global warming impact of carbon dioxide.)

The EPA has a program called the Natural Gas STAR Program, designed to encourage oil and gas companies to voluntarily reduce their GHG emissions by following GHG reduction technologies and practices. EPA reported that industry partners in its STAR Program achieved GHG emission reductions totaling 92.3 billion cubic feet. This is equivalent to the annual greenhouse gas emissions from approximately 6.8 million passenger vehicles.

Companies producing oil and gas have reported success in utilizing a number of methane reduction measures, including replacement of high-bleed pneumatic controllers with low-bleed pneumatics, installing plunger lifts, using "green" completions (not venting gas produced during completion operations), replacing gas-actuated pumps with solar electric pumps, and utilizing vapor recovery units (devices that capture vapor emitted from storage tanks and recycle it back into the production stream), and conducting regular inspections of facilities to identify and reduce fugitive leaks from valves, flanges and other connectors.

We may expect that federal agencies like the BLM and the Minerals Management Service, who are responsible for leasing of federal lands, will move toward imposing requirements on oil and gas operators to reduce their GHG emissions by using best available technologies like those enumerated in the plaintiffs' petition in this case. Those same technologies could be used to reduce emissions in and around the Barnett Shale, where residents are increasingly complaining about emissions from oil and gas compressors and other facilities.

The Wall Street Journal reported today that the Energy Information Administration will revise the way it estimates U.S. natural gas supplies, after concluding that its current method significantly over-estimates supply. An analysis has concluded that there are discrepancies of as much as 12% between the total gas supply (gas produced or imported) and gas demand (gas consumed or stored). In December, the EIA reported gas supply at 87.8 bcf/day and total demand of 80 bcf/day. The high estimates for supply may have unnecessarily depressed prices.

The EIA requires the nation's largest producers to file a monthly report, Form 914, to report production; based on that report and its models, EIA estimates production by smaller producers. EIA has been less able to account for smaller companies' production, and it is believed that this is in part a result of shale development and other advances in technology.

Speaker of the House Joe Strauss has charged the House Committee on Energy Resources as follows for the next legislative session:

"Survey current local ordinances governing surface use of property in oil and gas development. Recommend changes, if any, to the authority of the Railroad Commission to regulate the operation of oil and gas industries in urban areas of the state, particularly the Barnett Shale."

It seems evident from this charge that operators in the Barnett Shale will be asking the Texas Legislature to curtail the authority of municipalities to issue drilling permits for areas within their jurisdiction, or at least to limit what conditions they can place in those permits. Drilling ordinances such as those in Fort Worth and surrounding cities are becoming quite sophisticated, and place significant conditions on the granting of permits, including distances from houses and other structures, sound limits, handling of frac water, produced water and other wastes, safety requirements, traffic, and damage to surrounding streets. The City of Grapevine has revised its drilling ordinance to require an 8-foot masonry wall around the wellsite and shrubbery between 3 and 5 feet high along the wall. The City of Flower Mound is considering revision of its drilling ordinance to require companies to report their airbrorne emissions and use vapor recovery technology. In some cases, municipal ordinances are so stringent that as a practical matter they prevent drilling within city limits. I expect that eventually constitutional takings claims will be made against cities whose restrictions prevent any mineral development within their limits.

If the Legislature restricts municipal permitting authority, it could enlarge the requirements that the Railroad Commission must impose, or at least consider, when granting permits in urban areas, to include environmental considerations. The Austin Court of Appeals recently held that the Commission must consider the impact of traffic when ruling on an application for a disposal well permit. The Commission has appealed that decision, and the Texas Supreme Court has agreed to consider the case. Texas Citizens for a Safe Future and Clean Water v. Railroad Commission of Texas, 254 S.W.3d 492 (Tex.App.-Austin 2007, review granted March 12, 2010). It appears that the Commission would not relish the idea of regulating issues of traffic, noise, safety and pollution issues in urban settings, in connection with applications for well permits.

In a previous post I reported on the application of Devon Energy asking the Texas Railroad Commission to include in the new Field Rules for the Carthage (Haynesville Shale) Field a provision allowing it to drill horizontal wells across lease or pooled unit boundaries.  These new rules apply to wells drilled in the Haynesville and Bossier formations in Harrison, Nacogdoches, Panola, Shelby and Rusk Counties in East Texas. Devon asked that the rules provide what it calls a "default allocation method" for horizontal wells drilled across unit boundaries.The rule proposed by Devon reads as follows:

"Operators shall be permitted to drill and complete horizontal wells that traverse one or more units and/or leases as long as that operator has a lease or other mineral ownership right to produce from each such unit or lease. If such a well is not already subject to an agreement regarding the allocation of production, the following allocation formula will be presumed to constitute a fair and reasonable allocation of production from a well in this field and shall be utilized by the Commission in assigning acreage attributable to the separate units/leases traversed by the horizontal drainhole: an allocation of acreage and production to each of the units and/or leases traversed by and completed in the horizontal well based on the percent of said horizontal well from first take point to last take point that lies under each unit or lease."

The Commission concluded that it had no authority to adopt such a rule, because pooling is a contractual issue between private parties, and (except as provided in the Mineral Interest Pooling Act) the Commission has no right to impose allocations of production among different tracts penetrated by a horizontal well.

In its appeal, Devon argues that the Commission's refusal to adopt its proposed "allocation rule" is arbitrary and an abuse of its discretion, without a rational basis, discriminates against producers in the Carthage Field, and will result in the waste of oil and gas.

I believe that Devon has little chance of forcing the Commission to adopt its proposed "allocation rule." But if it is successful, it is certain that operators in the Barnett Shale and other shale fields now being developed in Texas will ask for a similar rule. Such a rule would have significant impacts on royalty owners and their rights to consent to pooling of their royalty interests.

 

Chesapeake Energy Corporation summarized its activities in the country's "Big 6" shale plays in its Operational Update issued on February 16. The report reveals the huge impact Chesapeake has had on shale plays from New York to South Texas.

Chesapeake is the eighth largest E&P company ranked by total assets according to the Oil & Gas Financial Journal, behind ExxonMobil, Chevron, ConocoPhillips, Anadarko, Marathon, Occidental and XTO Energy. It also ranks eighth in exploratory spending and market capitalization, and twelfth in total revenue. (Chesapeake's market cap is 18% of ExxonMobil's.) In 2009, Chesapeake drilled 1,148 gross operated wells, which it called "the industry's most active drilling program," spending $2.941 billion. Its leashold inventory at the end of 2009 was 13.7 million net acres.

Here are some highlights from Chesapeake's report:

 

Continue reading "Chesapeake Shale Plays" »

The debate over the safety of hydraulic fracturing continues. The Environmental Working Group, a Washington-based non-profit environmental advocacy organization, has issued a white paper, "Drilling Around the Law," calling for fracking to be regulated under the Safe Drinking Water Act and to require public disclosure of chemicals used in frac fluid. The EWG claims that "companies that drill for natural gas and oil are skirting federal law and injecting toxic petroleum distillates into thousands of wells, threatening drinking water supplies from Pennsylvania to Wyoming." EWG claims that fracking has been linked to drinking water contamination and proeprty damage in Colorado, Ohio, Pennsylvania, Wyoming and other states, citing articles written by Abrahm Lustgarten in ProPublica, another non-profit organization.

Meanwhile, Chesapeake has published on its website a "Fact Sheet" listing the chemicals used in its frac fluids in the Barnett Shale. The list includes "petroleum distillate," which Chesapeake describes as a "friction reducer," describing it as a product "used in cosmetics including hair, make-up, nail and skin products." The website shows that 99.5% of frac fluid is made up of water and sand, and only .5% is made up of additives, including "petroleum distillate." But the site does not show what percentage or volume of "petroleum distillate" or other additives are used in the frac fluid, or what kind of petroleum distillate is being used.

Another energy organization, Energy In Depth, has published a response to the EWG's white paper on fracking, "When Gummy Bears Attack." its author, Chris Tucker, cites data from the U.S. Department of Energy to show that "petroleum distillate" represents .088% of the volume of frack fluid. He says that petroleum distillates are used in lip gloss, sunscreen and gummy bears.

So what is "petroleum distillate"? Purdue University describes "petroleum distillates" as including all products derived from the distillation of petroleum, from diesel fuel to petroleum jelly to waxes and asphalts:

"Petroleum distillates are found in a wide variety of consumer-products including lip gloss, liquid gas, fertilizer, furniture polish, pesticides, plastics, paint thinners, solvents, motor oil, fuels and hundreds of other products. Petroleum distillates listed commonly on labels of general household products are those that distill off around naphthas. Petroleum jelly, a petroleum distillate product, is generally regarded as nontoxic.

"Petroleum distillates contain both aromatic hydrocarbons (carbon rings) and aliphatic hydrocarbons (straight carbon chains). The chemical structure of the hydrocarbon largely defines the nature and behavior of these compounds. Aromatic hydrocarbons are the most toxic compounds found in petroleum products. Most aromatic hydrocarbons are long-term toxins and known cancer causing agents. These aromatic compounds are found in all crude oils and most petroleum products. Many aromatic hydrocarbons have a pleasant odor and include such substances as naphthalene, xylene, toluene, and benzene. Aliphatic hydrocarbons are flammable and may be explosively flammable. Aliphatic hydrocarbons include methane, propane, and kerosene.

"Aliphatics and aromatics pose a special health risk if ingested and vomited. When swallowed, the lighter, more volatile distillate products can be sucked into the lungs interfering with the lung's functions and chemical pneumonia may result. Aspiration of fluid into the lungs can occur both during swallowing and vomiting of the product. Upon skin contact, petroleum distillates can produce local skin irritation and sensitivity to light in some individuals. Environmentally, many of the petroleum distillate products add to smog and water pollution due to improper disposal or during their manufacture and use."

The controversy over frac fluids has made the Wall Street Journal.

The industry claims that hydraulic fracturing is safe and is necessary to tap oil and gas reserves in the U.S. to reduce our dependency on foreign resources. Environmental groups claim that frac fluid can cause contamination of drinking water and should be closely regulated. Much of the debate appears to suffer from a lack of reasonableness and objectivity.

 

 

The Mayor of tiny Dish, Texas, north of Fort Worth, continues to stir up controversy with his claims of air pollution from oil and gas activities causing health concerns in his community. The mayor appeared at the RRC's January 12 open hearing. You can watch his testimony here (go to item 17 on the agenda). The mayor's appearance was prompted by an item placed on the agenda by Commissioner Michael Williams, which in turn had been prompted by a letter sent to the Commissioners by State Rep. Ron Burnam. Rep. Burnam's letter asked the RRC to place a moratorium on permits for wells in the Barnett Shale around Fort Worth until the Texas Commission on Environmental Quality (TCEQ) has finished its investigation of air quality in the area. In response, Commissioner Williams proposed that the Commissioners write a letter to the Texas Attorney General asking for a formal opinion whether the RRC has authority to issue such a moratorium. (Rep. Burnam has also asked the City of Fort Worth to issue a similar moratorium on well permits in the city limits.) I have written about the controversy concerning the town of Dish in a previous post.

Continue reading "Dish Mayor Calvin Tilman Testifies at Railroad Commission" »

The information below is from the Energy Information Administration.  Note the wide variation in City Gate and Wellhead Prices among different states:

 

Below is the same information in graph form.  Why would average residential gas prices in Texas be $12.88 per mcf, while residential prices in California and Minnesota -- far from natural gas production -- be less than $10 per mcf? Why such variations in Residential prices?

 

Exxon Mobil announced that it would acquire XTO Energy in an all-stock deal worth $41 billion. The acquisition is viewed as Exxon's decision to enter the domestic onshore gas shale play, which to date has been developed almost exclusively by independent producers. But the deal includes an exit clause in the event Congress passes legislation that would make hydraulic fracturing illegal or "commercially impracticable." Shale gas development would be impossible without hydraulic fracturing technology. Bills are pending in Congress (known as the FRAC Act) to subject fracturing to federal regulation under the Safe Drinking Water Act. The bills would require companies to publicly disclose the chemicals used in frac fluids. And U.S. Rep. Ed Markey, Dem. Massachusetts, said he would hold hearings in the House Energy and Commerce Committee to review the Exxon-XTO deal and to address environmental concerns about hydraulic fracturing.

Dish is a town of about 200 residents north of Fort Worth, Texas. The mayor and town council have recently become concerned about emissions from gas compressors in and around the town, from the Barnett Shale gas development. Large compressor stations are located near Dish; these stations have big internal combustion engines that compress gas to move it through gas transmission lines in the area. The town hired an environmental firm, Wolf Eagle Environmental, to conduct air quality tests and has complained to the Texas Commission on Environmental Quality. The small community has now become the focus of the larger debate over the impact of Barnett Shale wells on air quality in the Dallas-Fort Worth area and the impact of oil and gas drilling and production activity on the environment generally.

 

Continue reading "Tiny Town of Dish, Texas Stirs Up Hornet's Nest Over Air Pollution in Barnett Shale" »