Recently in Hydraulic fracturing Category
I recently ran across an article on the Energy In Depth website titled "Turning Natural Gas Into Water: Hydraulic Fracturing Doesn't Deplete Water Supplies." Energy In Depth is a website of the Independent Petroleum Association of America dedicated to "a research, education and public outreach campaign focused on getting the facts out about the promise and potential of responsibly developing America's onshore energy resource base " The article responds to an argument made by many organizations concerned about the large quantities of water used in fracing. The concern is that, while many uses of water return that water to the water cycle, water used in fracing is usually disposed of by injecting it underground, where it will never return to the water cycle.
Energy In Depth's response to this argument is that, while injecting the used frac water -- called "flowback" -- does remove that water from the water cycle, the burning of the gas (or oil) produced by the wells creates more water than was used in the fracing of the wells. So, the argument goes, fracing of wells actually "creates" new water that is added to the water cycle. EID's article goes on to calculate that, while a typical Marcellus gas well will remove 4 million gallons of water from the water cycle, that well will produce two billion cubic feet of gas which, when burned, will yield about 22 million gallons of "new" water. Within the well's first six months of production, the gas it produces will create more than 4 million gallons of water when burned as fuel. Problem solved!
I asked a hydrologist friend of mine to look at EID's calculations. He agreed that their math is correct, but he cautioned that the problem is not so simple. EID's argument assumes that the energy created by burning the natural gas from EID's typical well would not have been created by the burning of other fossil fuels. If, in other words, the gas is burned to create electricity, and if that electricity would have been created by burning coal if the well had not been drilled, then the net result is that water has been lost to the water cycle by injecting the flowback from the well.
EID's argument also fails to consider local conditions. Almost all of the water used for fracing in the Eagle Ford and in the Permian Basin in West Texas is groundwater. Those groundwater resources are already being depleted much faster than they are being recharged, mostly from agricultural and municipal demand, but exacerbated by the current drought and the demands of the oil industry. Even though the burning of the oil and gas produced from those areas does produce new water molecules into the water cycle, that fact does not replenish the aquifers or increase the chances of rain in those arid parts of our state.
The US Energy Information Administration recently projected that world consumption of energy from all fuel sources would increase by 56% through 2040. Most of that increase will come from burning fossil fuels.
Burning all of that fossil fuel will certainly create lots of "new" water. Is that a good thing for the environment?
Energy generation uses huge quantities of water. Nuclear plants as well as electric generation using fossil fuels require water for coolant. While that water stays in the water cycle, it is nevertheless a demand that must be met, and in Texas that demand is increasing exponentially. Only wind and solar energy need no water to generate electricity, and - even though Texas is the US leader in wind energy -- wind and solar are as yet a small part of electricity production.
A recent article in the Christian Science Monitor calls for recyclying of frac water. Some companies are experimenting with use of brackish (salty) water aquifers. EID and its sponsoring companies would do well to increase industry's efforts to reduce or eliminate use of underground water in hydraulic fracturing.
A memorial service, open to the public, will be held today for wildcatter and philanthropist George P. Mitchell - actually, three memorial services, as befits one of the great Texans of the 20th century. The Houston Chronicle in fact named him Houstonian of the Century. By all accounts, he was not only an entreprenurial genius, but a kind and generous man, a family man, and a man who gave back to his communities in many ways.
In one of his last public interviews, Mr. Mitchell addressed the issue of the safety and environmental risks of hydraulic fracturing and horizontal drilling. I wrote about that interview. He said that he supports tough regulation of independent operators. "I've had too much experience running independents," Mitchell said. "They're wild people. You just can't control them. And if it doesn't do it right, penalize the oil and gas people. Get tough with them."
Last year, Mr. Mitchell and Mayor Michael Bloomberg published an op ed piece in the New York Times supporting tighter regulation of the industry. What they said bears repeating. They pledged that their foundations
will support organizations that seek to work with states and industries to develop common-sense regulations that will protect the environment -- and ensure that the industry can thrive.
We will encourage better state regulation of fracking around five key principles:
Disclosing all chemicals used in the hydraulic fracturing process;
Optimizing rules for well construction and operation;
Minimizing water consumption, protecting groundwater and ensuring proper disposal of wastewater;
Improving air pollution controls, including capturing leaking methane, a potent greenhouse gas; and
Reducing the impact on roads, ecosystems and communities.
The latest research, including peer-reviewed studies out of Carnegie Mellon University and Argonne National Laboratory, suggests that if properly extracted and distributed, the impact of natural gas on the climate is significantly less than that of coal. Safely fracking natural gas can mean healthier communities, a cleaner environment and a reliable domestic energy supply right now.
We can frack safely if we frack sensibly. That may not make for a great bumper sticker. It does make for good environmental and economic policy.
Not words from a stereotypical Texas wildcatter. The industry would to well to follow his advice.
The drought in Texas, along with improved recyclying technology, has driven efforts to increase recycling of water used in hydraulic fracturing of wells. According to one estimate, the fracing of wells in 2011 consumed on the order of 135 billion gallons of water - about 0.3 percent of total U.S. freswater consumption. (Golf courses in the U.S. consume about 0.5 percent of all freswater used in the country.) But if you own land in the Eagle Ford field, those numbers don't mean much. Water use in some counties is lowering the water table in the Carrizo-Wilcox aquifer, the principal source of frac water for the Eagle Ford, causing some existing wells to dry up. In West Texas, the lack of available groundwater has forced companies to look at recyclying their frac water to extend the useful life of the water they can find for fracing.
Two bills now pending in the Texas legislature - House Bills 3537 and 2992 - would require the Texas Railroad Commission to develp rules to require rthe recycling and reuse of frac water returned from wells. The Commission has recently adopted rules to make it easier for operators to recycle water. And another bill, House Bill 379, would impose a 1-cent-per-barrel fee on wastewater disposed of in commercial injection wells.
Devon Energy, a leader in recycling of frac water in the Barnett Shale, testified to Texas lawmakers that recycling is 50 to 75 percent more expensive than sending frac water to injection wells. There are now about 50,000 injection wells in Texas, and the number is growing rapidly. Recyling is much more common in the Marcellus, where injection wells are not available and water must be hauled long distances for disposal.
The talk about recyling of frac water has raised an interesting legal question: whose water is it?
Groundwater is part of the surface estate in Texas. The owner of the mineral estate has the right to use so much of the surface estate - including groundwater - as is reasonably necessary to explore for and produce the minerals. Typically, an oil and gas lease grants the lessee the right to use groundwater, just as it grants the lessee the right to use the surface of the land, to explore for and develop the oil and gas under the leased property. Unless the lease provides otherwise, the lessee has no obligation to compensate the surface owner for the groundwater used. The operator may drill a water well and use that water for drilling and fracing wells on the lease, without compensation to the surface owner.
If the owner of the mineral estate also owns the surface of the land, the lease may require the lessee to compensate the lessor for use of the surface estate. In such instances in Texas, leases now often require the lessee to pay for groundwater used, at up to 50 cents per barrell or more.
Landowners in Texas also have sometimes contracted to sell their groundwater to operators for use in fracing wells. The operator, after contracting with one surface owner to obtain a groundwater supply, may build a large holding pond to store and use water for fracing of wells located on several leases in the vicinity of the pond, piping the water to its wells.
In those instances where the groundwater is sold to the operator, the operator has title to the water and should be able to recycle and use it as it pleases. But where the operator has taken groundwater under its general right to use the surface estate pursuant to its lease, the issue is less clear. The operator has the right to use the water, but may not acquire title to the water. Until recycling technology came about, the used frac water was just a waste product of the drilling operation that had to be properly disposed of. Once water is recycled, it has an economic value, and the surface owner of the property may claim that the water still belongs to it.
This is just one of the many interesting new legal issues raised by new technology in the oil field.
The E&P industry is continuing to face public criticism of its use of fresh groundwater in fracing wells and its failure to disclose the chemicals added to frac water.
On February 5, the Investor Environmental Health Network (IEHN) issued a press release announcing that shareholders have filed resolutions with Cabot O&G, Chevron, Exxon Mobil, EOG Resources, ONEOK, Pioneer Natural Resources, Spectra Energy, Range Resources and Ulta Petroleum challenging the companies "to quantifiably measure and reduce environmental and societal impacts" of their exploration activities. The resolutions focus on water issues, asking the companies to disclose the amount and sources of water used, how they track and measure naturally occurring radioactive materials (NORM) in frac water, whether and to what extent the companies use closed-loop systems in handling frac water, and what efforts are being made to reduce the amount of fresh water used. Shareholder proposals were filed by Calver Investments, Green Century Capital Management, the New York City Office of the Comptroller, the New York State Common Retirement Fund, the Sisters of St. Francis of Philadelphia, and Trillium Asset Management. IEHN and the Interfaith Center on Corporate Responsibility published a report in 2011, "Extracting the Facts: an investor guide to disclosing risks from hydraulic fracturing," intended to list and encourage best risk management practices by E&P companies, including reducing and disclosing all toxic chemicals, minimizing fresh water use by substituting non-potable sources, and using closed-loop systems to store waste waters.
Last week, New York Comptroller Thomas DiNapoly announced that the state's pension fund had reached an agreement with Cabot O&G to disclose its practices for minimizing the use of toxic chemicals in frac fluids. DiNapoli withdrew his shareholder proposal submitted for Cabot's upcoming proxy statement. DeNapoli has negotiated similar agreements with Hess, Range Resources and SM Energy.
Halliburton, which provides frac fluids for the industry, has developed a "green" frac fluid called CleanStim that uses only food-industry additives. Halliburton production manager Nicholas Gardiner said that Halliburton has developed a chemistry-scoring system for fracfluids, with lower scores being better. CleanStim has a zero score, he said, but is "relatively more expensive" than many traditional fracking fluids. Terry Engelder, a geologist at Penn State, said: "Eventually industry would like to end up with a mix of just water, sand, and food-grade additives. Companies are learning to deal with fewer and fewer additives."
The Texas House Energy Resources Committee held a hearing last week about fracing and water use. Industry spokesmen testified that they are using more brackish water and reusing flowback frac water; recycling water; and covering their retention ponds that store fresh water to limit evaporation. A spokesman for Fountain Quail Water Management said that 900 million gallons of flowback water have been recycled back to freswater in the Barnett Shale over the past nine years. He also announced formation of the Texas Water Recycling Association. A Devon Energy spokesman saidd that Devon had recycled about 700 million gallons of frac water since 2005. He said it costs 50 to 75% more than disposing of the water by injection. NBC News reported on a new water desalination technology that can clean up brackish water so that it can be used in fracing.
Meanwhile, Texas' law on disclosure of chemicals in frac fluds has come under criticism because of its trade-secret "loophole." A Bloomberg report said a sample of frac fluid disclosures from 370 wells reported in August 2012 showed that Baker Hughes averaged 9.1 non-disclosed ingredients per well, Halliburton averaged 9.3, and Superior Well Services averaged 32.5. Lon Burnam, the Democratic state legislator who co-authored the law, said that "this disclosure bill has a hole big enough to drive a truck through."
On another topic: a final good-bye to Aubrey McClendon, who has resigned from Chesapeake, the company he founded. He receives a nice parting gift of $45.2 million over the next four years and $33.5 million in restricted stock. He was previously removed as Chairman of the Board because of heavy criticism of alleged conflicts of interest and the company's poor market performance. It will be interesting to see how Chesapeake survives without him. While much of the criticism of his tenure is undoubtedly deserved, his huge contribution to the natural gas boom of the last ten years should not be forgotten.
Here are two good websites that provide interesting and balanced views about energy production and consumption: The Rational Middle, and Think Progress. The Rational Middle is a series of films by the people that produced the movie Haynesville - A Nation's Hunt for an Energy Future. Its goal is to encourage rational thinking about our energy future and establishing achievable goals toward sustainable energy. The films about unconventional resources and the risks of hydraulic fracturing are worth looking at.
Think Progress's climate page introduces thought-provoking statistics about our nation's energy sources and uses. For example:
56.2% of the nation's energy is wasted each year - from the Lawrence Livermore National Laboratory:
Check them out.
The University of Texas withdrew a study published earlier this year by UT Austin's Energy Institute, "Fact-Based Regulation for Environmental Protection in Shale Gas Development," after review by an independent commission appointed by the University. That review was prompted by a report of the Public Accountability Initiative, a non-profit watchdog group, which revealed that Dr. Charles Groat, professor at the Jackson School of Geosciences at UT and director of the study, sits on the board of Plains Exploration and Production Company and received cash and stock compensation from Plains of more than $1.5 million since 2007, but did not reveal that relationship in connection with the report. Dr. Groat has since retired, and the Head of the Energy Institute, Dr. Raymond Orbach, has resigned as head of the institute.
The independent review commission found that Dr. Groat's failure to disclose his ties with Plains was "very poor judgment," and that UT's conflict of interest policy should be strengthened (UT has done so). The commission also found several other faults with the report:
- The report was presented as having scientific findings, but most of it was based on "literature surveys, incident reports and conjecture," and was not in fact "fact-based".
- The summary of the report issued in a UT press release was misleading and "seemed to suggest that public concerns were without scientific basis and largely resulted from media bias."
- The study was "not subject to serious peer review and therefore [was] not ready to be considered for public release as fact-based work." The commission recommended that the study be withdrawn (which UT has done):
Because of the inadequacies herein cited, publications resulting from the Energy Institute's project on shale gas fracturing currently displayed on the Energy Institute's website should be withdrawn and the document "Separating Fact from Fiction in Shale Gas Development," given its basis in the above, should not be further distributed at this time. Authors of the white papers should be allowed sufficient time and opportunity to finish their work, preparing their papers for submission for independent review by a broad panel of independent scientists and policy experts. Even if not published in a professional journal this approach is deemed appropriate when dealing with highly contentious issues. The summary paper should be redrafted to accurately reflect these revised white papers, with strong involvement from the Senior Contributors.
UT's press release yesterday can be found here.
The report of the independent review commission can be found here.
Public Accountability Initiative's critique of the study can be found here.
Clearly a black eye for UT.
This summer, the Department of Interior's Bureau of Land Management issued proposed rules relating to disclosure of the content of frac fluids and handling of frac fluids used in wells drilled on puclic lands managed by the BLM. Last week a group of Congressmen led by Congressman Edward J. Markey, D. Mass., head of the House Natural Resources Committtee, have submitted an extensive letter commenting on the proposed rules.
The letter criticizes BLM's rules for (1) not requiring disclosure of chemicals in frac fluids prior to drilling of a well rather than after the fact, (2) proposing to use FracFocus as the method for disclosure of frac fluids, (3) allowing flowback fluids to be stored in earthen pits, (4) not imposing requirements for proper well construction, cement and casing design and installation, and (5) not establishing minimum setbacks between wells and public buildings to minimize harm from air emissions during well completions.
As I have reported earlier, the Texas Railroad Commission recently published proposed rules tightening regulations on well construction and cementing, as well as more stringent regulation of disposal wells, to better protect against contamination of groundwater.
I recently spoke at a Continuing Legal Education Program for Texas real estate attorneys about regulation of hydraulic fracturing. My job was to give a short overview of the development of fracing and horizontal drilling in the US and its impact on production and the economy. Here are some slides I used in the presentation.
Below is a photo of a well during the process of fracing. The trucks are big hydraulic pumps, all hooked up to a manifold that is hooked to the well. The earthen tank in the picture is filled with fresh water used in the fracing operation. The water is mixed with sand and chemicals and pumped into the well under high pressure to "frac" the formation. Note that these pad sites are larger than for conventionally drilled wells. One pad site may be used to drill three or six or more wells. The horizontal lateral of the well will be 5,000-8,000 feet.
Below is a schematic for a horizontal well, intended to show the distance horizontally between fresh water aquifers and the depth at which the well is completed, and the multiple layers of casing installed between the well and the aquifer to protect fresh water. The distance between fresh water zones and the producing formations varies by field. For the Barnett Shale, fresh water is at about 1,200 feet, and the Barnett Shale is it about 6,500-8,000 feet. For the Haynesville Shale in Lousiana and East Texas, fresh water is at about 400 feet and the formation is at 10,500 to 13,500 feet. For the Marcellus Shale in Pennsylvanie, freshwater is at about 850 feet, and the formation is between 4,500 and 8,500 feet. Here is a video from Chesapeake showing how wells are drilled horizontally.
Horizontal wells are frac'ed in "stages." Segments of the horizontal leg of the well are isolated, holes are punctured or "shot" through the well casing, and frac water is pumped into that segment of we well, through the perforations in the casing, and into the formation, fracturing the rock to allow oil and gas to escape into the wellbore. The pressure is then released, the frac water flows back up the hole, and the process is repeated for a different segment. Wells may be shot in 12 or more stages. Here is a video showing how the process works, created by Chesapeake.
Below is a map showing the major shale plays in the US. Additional unconventional shale plays are being discovered and developed.
Below is a graph showing the number of gas wells producing in Texas over time. The number of wells increased significantly beginning in 2003, when shale drilling took off, and is approaching 100,000 wells.
The graph below shows the potential for gas production from major shale plays according to a study by MIT.
As gas production in the US increased, prices predictably declined. The result has been huge savings for US consumers, both residential and commercial. It has not been good news for the coal, nuclear and wind energy industries, which have to compete for natural gas as fuel for electric generation.
Another result of the gas glut is that exploration companies have moved to shale plays that produce oil and other liquid petroleum constituents, as shown by the graph below.
One of the largest oil shale plays is the Eagle Ford in South Texas, which has commenced development only in the last couple of years. There are now some 4,000 wells producing from the Eagle Ford formation. To date, those wells have produced 37 million barrels of oil and 311 billion cubic feet of gas. (Oil wells in the Eagle Ford also produce gas, thereby adding to the gas glut and holding gas prices down.) There are 250 rigs drilling in the Eagle Ford, and there are predictions that the field will be producing 900,000 bbls/day by the end of 2012, with reserve estimates of an average of 500,000 BOE per well.
Below is a map of the Eagle Ford. The formation dips (gets deeper) from northwest to southeast. The three colors on the map represent the "oil window" on the northwest flank of the field, the "gas window" on the southeast flank, and the "liquids window" in the middle. To date, the best wells are in the liquids window, and produce both oil and gas.
The graph below shows the increase in production from the Eagle Ford over the last 3 years, and the increased number of rigs in the field, over time.
Fracing of wells uses a lot of fresh water -- from 3 to 5 million gallons per well. But the industry points out that this water use is a small percentage of the total water used in the areas of the shale plays:
The Pacific Institute has issued a study of issues related to hydraulic fracturing and water resources: Hydraulic Fracturing and Water Resources: Separating the Frack from the Fiction. The Pacific Institute is a non-profit research and policy organization based in Oakland, California. The study is largely a summary of interviews of environmental and industry experts and of research in the area; it provides a good summary of the present issues surrounding fracing and the literature on the subject.
The authors comment on the debate of whether hydraulic fracturing is the cause of any groundwater contamination by characterizing it as an issue of definition: those in the industry, they say, define the term narrowly as including only the actual process by which fluids are injected into the wellbore under pressure to fracture the formation. The authors elect to define the term more broadly, "to include impacts associated with well construction and completion, the hydraulic fracturing process itself, and well production and closure." It is true that people outside the industry have tended to use the term "fracing" to include anything that can go wrong in the process of drilling, completing and producing a well and cause contamination. It is a mistake, however, to use the term to include risks of contamination from well construction, production and closure; those risks occur with all wells, whether they are vertical or horizontal and whether they are completed in shale or conventional formations.
The authors discuss the following issues surrounding "fracing," as they broadly define it:
The study has the following graphic showing the amount of water used in fracing:
The authors point out that use of water for fracing is a "consumptive" use, meaning that the water is not available for subsequent use but is generally disposed of by injection into disposal wells, so that it leaves the water cycle. They cite a report that, in Texas, companies have recently been paying between $9,500 and $17,000 per million gallons ($.40 to $.70 per barrel) for frac water. In addition to affecting the availability of water for other uses, withdrawal of such large quantities of water can adversely affect water quality, according to the study: "withdrawals of large volumes of water can adversely impact groundwater quality through a variety of means, such as mobilizing naturally occurring substances, promoting bacterial growth, causing land subsidence, and mobilizing lower quality water from surrounding areas."
Groundwater Contamination Associated with Well Drilling and Production
This is the problem of defective casing, which has been documented to cause groundwater contamination by methane. Such contamination can also take place through old abandoned wellbores when a well in close proximity is fraced. The authors cite the controversial study in Pennsylvania that found methane levels in drinking water wells located within 1 kilometer from a gas well were 17 times higher than in water wells outside of active gas production areas. And the authors discuss the controversial EPA study of wells in Pavilion, Wyoming and the contamination of groundwater by methane in Dimock, Pennsylvania as associated with poor casing practices.
The authors include contamination caused by poor wastewater management practices as a problem associated with fracing - poorly constructed disposal wells, attempts to use municipal treatment facilities to treat frac water, and the long hauls of flowback water to distant disposal wells.
Another "fracing" problem the authors associate with fracing: they estimate 3,950 truck trips per well for horizontal shale wells, including hauling of fresh water to the wells.
Surface Spills and Leaks
The authors list the following causes of land and groundwater contamination under this heading: accidents and equipment failure during onsite mixing of frac fluids; vandalism; illegal dumping and disposal of flowback water; and truck accidents.
This is the risk of contamination caused by runoff from wellsites.
The authors call for more study of the effects of well operations in these areas, "to clarify terms and definitions associated with hydraulic fracturing, to support more fruitful and informed dialog and to develop appropriate energy, water, and environmental policy."
The Wall Street Journal published a front-page article in its December 6 edition, "Oil's Growing Thirst for Water," that highlights issues with the oil and gas industry's demand for water in the Eagle Ford and other shale plays. The article quotes Darrell Brownlow, a hydrologist and geochemist and a landowner in South Texas about whom I have written previously. The WSJ article highlights the coming conflict between the oil and gas industry's demand for water and the growing demands on groundwater in Texas.
According to Dr. Brownlow, it makes simple economic sense to use groundwater as a resource for oil and gas exploration: The WSJ says: "Mr. Brownlow ... says it takes 407 million gallons to irrigate 640 acres (one square mile) and grow abaout $200,000 worth of corn on the arid land. The same amount of water, he says, could be used to frack enough wells to generate $2.5 billion worth of oil. 'No water, no frack, no wealth,' says Mr. Brownlow, who has leased his cattle ranch for oil exploration."
Most of the Eagle Ford lies above the Carrizo aquifer, which stretches from Webb County on the Rio Grande River up through Fayette County. Dr. Brownlow, a hydrologist, concludes that there is plenty of water in the Carrizo, in most places, to meet the demands for frac water. His estimates:
- There are about 6 million acres in the Eagle Ford play, and a possible 20,000 oil and gas wells (one well per 300 acres).
- An average frac job uses 15 acre-feet of water (4,887,765 gallons, or 115,375.5 42-gallon barrels).
- So, the frac jobs on those 20,000 wells would use about 300,000 acre-feet of water over the life of the play.
- Current withdrawals from the Carrizo Aquifer are about 275,000 acre-feet per year; so the entire demand for frac water from Eagle Ford wells would equal about one year's withdrawal of water from the aquifer. At a rate of withdrawal of 275,000 acre-feet per year, groundwater management studies estimate that the Carrizo water table will drop an average of 30 to 35 feet by 2060.
Dr. Brownlow says that, if a successful Eagle Ford well makes 300,000 to 400,000 barrels of oil at $80/bbl, the return to the landowner would be $520,000 per acre-foot ($1.60 per gallon). In contrast, the return to a farmer using the same acre-foot of water to irrigate corn, peanuts or coastal hay would be $500 to $1,000 per acre, or about $250 per acre-foot of irrigation water. "The point here is that using groundwater from the Carrizo for hydraulic fracturing in the Eagle Ford Shale has enormous economic potential for landowners, oil production companies and the entire region. Moreover, from a geologic and water planning perspective, additional impact on the aquifer appears minimal," says Dr. Brownlow.
Below is an analysis of data from the Texas Water Development Board, done by the WSJ:
The oil and gas industry uses only 1.6% of the water consumed in the state. But this use is concentrated in areas where drilling activity is located, often in arid portions of the state, and the use is growing rapidly. As can be seen from the above graph of one water well, if your well is the one affected, it is an important issue. And the water used for fracing in the Eagle Ford is not returned to the ecosystem; it either remains in the formation, or if it returns to the surface, is it reinjected into licensed disposal wells.
In Texas, the oil and gas industry is exempted from regulation by local underground water districts, which have authority to permit and regulate withdrawals from underground aquifers. Those water districts are now in the middle of establishing "desired future conditions" for the aquifers within their jurisdiction and rules to assure that withdrawals are regulated so that those desired future conditions are met. Because those water districts have no authority to regulate wells used for oil and gas exploration, they cannot predict or control the effect of industry uses on their future supplies of water.
The issues raised by industry use of groundwater just go to prove the old Texas saying, "Whiskey's for drinkin', water's for fightin'."
Earlier this year, the 82nd Texas Legislature passed HB 3328, requiring the RRC to adopt rules requiring disclosure of chemicals in frac fluids. The draft rule would require operators to disclose chemical content of frac fluids on FracFocus, a website developed by the Ground Water Protection Council and the Interestate Oil and Gas Compact Commission. (The website contains a lot of good information about hydraulic fracturing and its benefits and risks.) FracFocus was launched on April 1, 2011. As of August 16, 2011, according to RRC staff, operators had registered 950 Texas wells on the website, including wells drilled by Anadarko, Chesapeake, Chevron, Conoco-Phillips, Devon, El Paso, Energen, EOG, Forest, Newfield, Occidental, Penn Virginia, Petrohawk, Pioneer, Plains, Range, Rosetta, Shell, Williams, and XTO. You can search for a well near you by using FracFocus's search feature. An example of the information disclosed can be found here: 4243935364-3212011-10792272-CHESAPEAKE.pdf The disclosure includes the percentage by mass of each chemical used in the frac fluid.
Under the proposed rule, an operator must also provide the same information with its completion report for the well, as part of the completion report. The completion report for all Texas wells can also be found on the RRC's website.
RRC's staff's discussion of the proposed rule estimates that 13,000 wells undergo frac treatment in Texas each year -- 85% of all wells drilled in Texas.
A supplier, service company or operator is entitled under the draft rule to claim trade-secret protection for a chemical additive. If such protection is claimed, the particular chemical and its concentration need not be provided, but the operator must disclose the chemical family of the ingrediant and the properties and effects of the chemical. The claim of trade-secret protection may be challenged by the landowner on whose property the well is drilled or any adjacent landowner, or by any state department or agency with jurisdiction over issues related to health and safety. Any such challenge must be filed within 2 years after the claim of trade-secret protection was filed. If a challenge is filed (with the RRC), the RRC refers the matter to the Texas Attorney General who makes a determination, based on evidence submitted by the person claiming trade-secret protection, of whether the identity of the chemical is in fact a trade secret under Texas law. The AG's determination may be appealed to a state district court. If a trade-secret exemption is claimed, a health professional or emergency responder may still obtain the information but must keep it confidential except to the extent it must be disclosed to protect health and safety.
An operator who fails to disclose as required by the rule may have its operating permit revoked.
The New York State Department of Environmental Conservation (DEC) has been engaged in a comprehensive review of the potential environmental impacts of development of the Marcellus Shale in New York since 2008. The DEC is the regulatory agency in New York responsible for issuing drilling permits and regulating oil and gas exploration and production. The DEC had previously studied the environmental impacts of hydraulic fracturing in 1992, at which time it issued a Generic Environmental Impact Statement recommending certain safeguards in that practice. In 2009, the DEC issued for public comment a "Draft Supplemental Generic Impact Statement" analyzing the impact of hydraulic fracturing of horizontal Marcellus wells. As a result of comments received, the DEC has issued a revision of that draft report, which will be finalized later this year and again issued for public comment. During this study, New York has imposed a moratorium on issuance of any permits for horizontal wells in the Marcellus Shale.
The Marcellus extends over a huge area from West Virginia through Pennsylvania and covers a substantial part of New York State. Potential Marcellus reserves in New York are huge, and exploration companies have leased huge areas in New York for exploration. New York landowners have watched impatiently as wells have been drilled in Pennsylvania, while environmental activists in New York have opposed any drilling in that state.
The most recent version of the New York DEC's study and recommendations is several hundred pages and provides a thorough study of the potential impacts of drilling Marcellus wells on the environment, including impacts on groundwater, surface water, air quality and wildlife. The report proposes many revisions to DEC's existing regulations concerning the construction of well pads, the drilling and casing of horizontal wells, the handling and disposal of frac fluids and chemicals, the disposal of returned frac water and drill cuttings, the use of best available technology to reduce emissions from equipment during drilling and completion operations, and the protection of groundwater and surface water. The report discusses the current state of technologies for use of fluids other than fresh water for hydraulic fracturing and for the recycling of frac water. The authors also discuss recent incidents in Pennsylvania of groundwater and surface water contamination from drillsites and their cause. There is a comprehensive summary of the geology of shale formations and water resources in New York.
WSJ Weighs In On Fracing Controversy
The Wall Street Journal gives its opinion on the dangers of hydraulic fracturing, siding with the industry: "The shale gas and oil boom is the result of U.S. business innovation and risk-taking. If we let the fear of undocumented pollution kill this boom, we will deserve our fate as a second-class industrial power."
Powell Shale Digest Issues Report on Eagle Ford
The Digest reported on wells drilled so far in Eagle Ford fields in Texas. Enough information is now publicly available to begin to see where the play is headed, and where it's most successful.
The counties with highest oil and gas production are Dimmit, Karnes, Webb and La Salle. The counties with the best results per well are Karnes and DeWitt:
Baker Hughes' oil rig count reached 1,000 for the first time since it began tracking oil and gas rigs separately in 1987. 843 oil and gas rigs are currently located in Texas.
Fracking has become more and more a topic in the general media and part of the state and federal environmental energy agenda, with new stories appearing daily. A sample:
Secretary of Energy Steveb Chu has appointed an advisory panel, officially called the Secretary of Energy Advisory Board's subcommittee on natural gas, to study the environmental issues around hydraulic fracturing and shale gas production. Members of the subcommittee are John Deutch, former head of the CIA during the Clinton administration, in the Department of Energy during the Carter administration, now a professor at MIT, and former board member of Schlumberger, Ltd.; Daniel Yergin, IHS Cambridge Energy Research Associates Chairman; Susan Tierney, Chair of the board of the Energy Foundation; Stephen Holditch, chair of the Department of Petroleum Engineering at Texas A&M; Fred Krupp, President of Environmental Defense Fund; Kathleen McGinty, former head of Pennsylvania's Department of Environmental Protection; and Mark Zoback, geophysics professor at Stanford University. Steven Chu, Secretary of Energy, has charged the subcommittee to make recommendations on ways to improve safety of fracking in 90 days, and offer advice to other agencies within six months on how they can better protect the environment from shale gas drilling. http://thehill.com/blogs/e2-wire/677-e2-wire/164057-overnight-energy-fracking . Beginnings of the subcommittee's work have not shown promise: at the first meeting of the committee, Dusty Horwitt of the Environmental Working Group said its chairman John Deutch should resign because of his former ties to Schlumberger and Cheniere Energy. On the other side, Republicans including Darrel Issa (R-Calif), chair of the House Oversight and Government Reform Committee, have said that Chu's subcommittee is composed primarily of Democratic appointees hostile to drilling interests.