Facts About Shale Gas
•Unconventional natural gas deposits are difficult to characterize overall, but in general are often lower in resource concentration, more dispersed over large areas, and require well stimulation or some other extraction or conversion technology. Extremely large natural gas in-place volumes are represented by these resources, and the US has produced only a fraction of their ultimate potential.
•Shale gas is defined as natural gas from shale formations. The shale acts as both the source and the reservoir for the natural gas. Older shale gas wells were vertical while more recent wells are primarily horizontal and need artificial stimulation, like hydraulic fracturing, to produce. Only shale formations with certain characteristics will produce gas. The most significant trend in US natural gas production is the rapid rise in production from shale formations. In large measure this is attributable to significant advances in the use of horizontal drilling and well stimulation technologies and refinement in the cost-effectiveness of these technologies. Hydraulic fracturing is the most significant of these.
•The consulting firm ICF forecasts that tight gas, coalbed methane, and shale gas will make a major contribution to future North American gas production. Unconventional gas production is forecast to increase from 42 percent of total US gas production in 2007 to 64 percent in 2020. Despite the current economic conditions, the long-term need for US natural gas should be strong enough to support these anticipated future production levels.
•With the tremendous success of the Barnett, Fayetteville and Woodford shales in the United States, the gas shale resource base will play a major role in the future natural gas production on which the nation will depend. Already the Barnett Shale gas play in Texas produces 6 percent of all natural gas produced in the Lower 48 states. Recent announcements of emerging plays in Appalachia, Northern Louisiana, British Columbia, and South Texas indicate the widespread potential of shale gas resources across North America. Each of these shale gas basins is different and each has a unique set of exploration criteria and operational challenges.
•The Potential Gas Committee, an incorporated, nonprofit organization that consists of knowledgeable and highly experienced volunteer members who work in the natural gas exploration, production and transportation industries issued its biennial assessment of the nation’s gas resources in June 2009. This study indicates that the United States possesses a resource base of 1,836 Tcf of natural gas. When combining these results with the Department of Energy’s latest determination of proved gas reserves, 238 Tcf as of year-end 2007, the United States has a future supply of natural gas of over 2,000 Tcf. At current consumption rates, this is enough natural gas to supply the nation for the next hundred years. This is an increase of more than 35% when compared to the Committee’s 2006 assessment. This increase is largely attributable to increased supplies from unconventional gas plays, specifically from shale gas development.
•In its April 2009 report, "Modern Shale Gas Development in the United States: A Primer," the US Department of Energy stated that at the US natural gas production rates for 2007 of about 19.3 Tcf, the current recoverable resource estimate provides enough natural gas to supply the US for the next 90 years. Separate estimates of the shale gas resource extend this supply to 116 years. Production of shale gas is expected to increase from a 2007 US total of 1.4 Tcf to 4.8 Tcf in 2020. The DOE report states that shale gas production potential of 3 to 4 Tcf per year may be sustainable for decades. The INGAA report stated that to achieve the forecast results, industry must have land access for drilling, a reasonable permitting process and adequate prices and demand for natural gas.
•In November 2008, the Interstate Natural Gas Association of America (INGAA) published a report, "Availability, Economics and Production Potential of North American Unconventional Natural Gas Supplies," that included an updated resource base for natural gas in the United States and Canada. The INGAA study states that the assessment of shale gas potential in the United States and Canada is a work in progress and there is a long way to go to understand remaining potential and implications for future natural gas production. The advance of drilling and well completion technologies, including hydraulic fracturing, has opened up plays in a number of different basins that were not previously considered to have economic potential. The volumes calculated for gas-in-place are extremely large, and a small difference in the estimated percentage of gas-in-place that is recoverable has a huge impact on estimates of recoverable resources.
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Updated:February 1, 2010
Friday, August 5, 2011
Shale Boom in Texas Could Increase U.S. Oil Output
Shale Boom in Texas Could Increase U.S. Oil Output
By CLIFFORD KRAUSS
Now the region is in the hottest new oil play in the country, with giant oil terminals and sprawling RV parks replacing fields of mesquite. More than a dozen companies plan to drill up to 3,000 wells around here in the next 12 months.
The Texas field, known as the Eagle Ford, is just one of about 20 new onshore oil fields that advocates say could collectively increase the nation’s oil output by 25 percent within a decade — without the dangers of drilling in the deep waters of the Gulf of Mexico or the delicate coastal areas off Alaska.
There is only one catch: the oil from the Eagle Ford and similar fields of tightly packed rock can be extracted only by using hydraulic fracturing, a method that uses a high-pressure mix of water, sand and hazardous chemicals to blast through the rocks to release the oil inside.
The technique, also called fracking, has been widely used in the last decade to unlock vast new fields of natural gas, but drillers only recently figured out how to release large quantities of oil, which flows less easily through rock than gas. As evidence mounts that fracking poses risks to water supplies, the federal government and regulators in various states are considering tighter regulations on it.
The oil industry says any environmental concerns are far outweighed by the economic benefits of pumping previously inaccessible oil from fields that could collectively hold two or three times as much oil as Prudhoe Bay, the Alaskan field that was the last great onshore discovery. The companies estimate that the boom will create more than two million new jobs, directly or indirectly, and bring tens of billions of dollars to the states where the fields are located, which include traditional oil sites like Texas and Oklahoma, industrial stalwarts like Ohio and Michigan and even farm states like Kansas.
“It’s the one thing we have seen in our adult lives that could take us away from imported oil,” said Aubrey McClendon, chief executive of Chesapeake Energy, one of the most aggressive drillers. “What if we have found three of the world’s biggest oil fields in the last three years right here in the U.S.? How transformative could that be for the U.S. economy?”
The oil rush is already transforming this impoverished area of Texas near the Mexican border, doubling real estate values in the last year and filling restaurants and hotels.
“That’s oil money,” said Bert Bell, a truck company manager, pointing to the new pickup truck he bought for his wife after making $525,000 leasing mineral rights around his family’s mobile home. “Oil money just makes life easier.”
Based on the industry’s plans, shale and other “tight rock” fields that now produce about half a million barrels of oil a day will produce up to three million barrels daily by 2020, according to IHS CERA, an energy research firm. Oil companies are investing an estimated $25 billion this year to drill 5,000 new oil wells in tight rock fields, according to Raoul LeBlanc, a senior director at PFC Energy, a consulting firm.
“This is very big and it’s coming on very fast,” said Daniel Yergin, the chairman of IHS CERA. “This is like adding another Venezuela or Kuwait by 2020, except these tight oil fields are in the United States.”
In the most developed shale field, the Bakken field in North Dakota, production has leaped to 400,000 barrels a day today from a trickle four years ago. Experts say it could produce as much as a million barrels a day by the end of the decade.
The Eagle Ford, where the first well was drilled only three years ago, is already producing more than 100,000 barrels a day and could reach 420,000 by 2015, almost as much as Ecuador, according to Bentek Energy, a consultancy.
The shale oil boom comes as production from Prudhoe Bay is declining and drilling in the Gulf of Mexico is being more closely scrutinized after last year’s Deepwater Horizon disaster.
What makes the new fields more remarkable is that they were thought to be virtually valueless only five years ago. “Everyone said the oil molecules are too large to flow in commercial quantities through these low-quality rocks,” said Mark G. Papa, chief executive of EOG Resources.
EOG began quietly buying the rights to thousands of acres in the Bakken and Eagle Ford after an EOG engineer concluded that the techniques used to extract natural gas from shale — fracking, combined with drilling horizontally through layers of rocks — could be used for oil. Chesapeake and a few other independents quickly followed. Now the biggest multinational oil companies, as well as Chinese and Norwegian firms, are investing billions of dollars in the fields.
The new drilling makes economic sense as long as oil prices remain above $60 a barrel, according to oil companies. At current oil prices of about $100 a barrel, shale wells can typically turn a profit within eight months — three times faster than many traditional wells.
But water remains a key issue. In addition to possible contamination of surface and underground water from fracking fluids, the sheer volume of water required poses challenges, especially in South Texas, which faces a severe drought and rapidly diminishing water levels in the local aquifer.
At the rate wells are being drilled, “there’s definitely going to be a problem,” said Bay Laxson, a local water official.
Dave Thompson, regional production superintendent for the oil company SM Energy said the industry knew that water issues were “an Achilles heel.” He said his company was building a system to reuse water in the field.
But unlike Pennsylvania and New York, where fracking for natural gas has produced organized opposition, the oil industry has been mostly welcomed in western and southern states.
Thanks to the drilling boom, the recession bypassed North Dakota entirely. Here in Dimmit County, Tex., the unemployment rate has fallen in half, and sales tax receipts are up 70 percent so far this year, allowing the county to hire more police officers and buy sanitation and road repair equipment.
“In my lifetime, this is the biggest thing I’ve ever seen,” said Jose Gonzalez, 78, a retired teacher and son of migrant farm workers, who leased mineral rights to Chesapeake for $27,000 and sold another plot for $100,000 to a company building an RV park for oil workers. “You can see I’m happy.”
Another Shale Boom: Hydraulic Fracturing and Shale Oil This Time
Another Shale Boom: Hydraulic Fracturing and Shale Oil This Time
Hydraulic fracturing continues to present new innovation opportunities on the energy scene which can/will transform the economy. See, for example, the front page report in the May 28, 2011 New York Times ("Oil Hidden in Shale Sets Off a Boom in Texas"). According to this report, hydraulic fracturing is now being used to recover oil from "low-quality" shale in South Texas including the Eagle Ford site. The Times reports that more than a dozen companies plan to drill up to 3,000 wells in the next 12 months. Moreover, the fields were thought to be valueless five years ago, per the Times. However, hydraulic fracturing and horizontal drilling were also developed for use with oil extraction, despite the larger molecules in oil compared to natural gas. Small-scale morphology including small diameter microholes and/or nanopores play a critical role in the extraction, and the small pore size can affect extraction. Of course, water remains a key issue as these developments move forward, particularly in areas of drought and limited water supply.
Chesapeake Energy, one company noted in this report, provides online the following media fact sheet regarding hydraulic fracturing:
Chesapeake Energy, one company noted in this report, provides online the following media fact sheet regarding hydraulic fracturing:
Shale Oil and Gas Exploration - Hydraulic Fracturing
Shale Oil and Gas Exploration - Hydraulic Fracturing
With the emergence of improved horizontal drilling and hydraulic fracturing techniques, shale oil and gas exploration is expanding rapidly across the nation in many shale formations, including the Barnett, Eagle Ford, Fayetteville, Haynesville and Marcellus Shale Plays. The growing use of this technology has also highlighted new environmental protection issues. TestAmerica has been at the forefront of these developments since 2008, providing critical analytical testing services on over 400,000 samples to date, supporting the environmental stewardship efforts of exploration firms, drillers, and the consulting engineering firms that support their activities. TestAmerica has designed and modified its testing services to take into consideration the naturally occurring conditions associated with each geologic formation, chemicals used in the fracturing process and state regulations that drive individual testing needs.
Maximizing Completions By Incorporating Geological Findings Into Profitable Hydraulic Fracturing Strategies
Maximizing Completions By Incorporating Geological Findings Into Profitable Hydraulic Fracturing Strategies
As the U.S. market becomes saturated with low-price shale gas, Oil & Gas E&P companies are increasingly focusing their resources on more lucrative liquid-rich shale plays including the Bakken, Niobrara and Eagle Ford in search of higher value tight oil deposits. Advances in hydraulic fracturing mean recovering tight oil from shale plays is becoming more and more economical and companies are rushing to acquire and exploit acerage in the formations where this oil is contained.
The Tight Oil From Shale Plays World Congress 2011 was the first conference to bring together senior decision-makers from the leading E&P companies in North America to share the cutting-edge geological and completions strategies, technologies and techniques that they are using to maximize the recovery of tight oil from shale plays.This event was the third in our groundbreaking Shale Series in which agendas are based on in-depth systematic research with over one hundred industry professionals per project and address the most challenging issues in the market today.
Day one took a critical approach to evaluating the leading methodologies and technologies used to interpret geological characterization in a way that can be directly applied to successful completions. The unique issues of measuring and interpreting data on unconventional rock mechanics, hydrocarbons in place, porosity, permeability and wetability are underpinned by the end goal of determining play viability and developing an oil-maximizing completions strategy.
Day two followed by examining how to integrate the critical geological findings into a completions strategy demonstrated by case studies and tried and tested best practices from leading operators. Cutting edge hydraulic fracturing technologies will be evaluated against production efficiency and take-away solutions will be provided for determining successful completions techniques using optimal fluid volumes, pump pressures, fluid compositions and natural fracture intersection.
ATTENDEES GAINED :
- Heard from key tight oil industry players on how to practically analyze rock property data to overcome the unique unconventional reservoir challenges
- Core and seismic data analysis methodologies were evaluated to determine best practices for integrating findings into a successful completions strategy
- The most accurate methodologies were be scrutinized for calculating EUR and scoping out return on investment for the next big play
- Completions strategies were broken down and examined to determine successful methods for integrating geological findings into the hydraulic fracturing plan
- Completions techniques and technologies were be evaluated against real life examples to show how they are maximizing oil recovery
Hydraulic Fracturing 101
Hydraulic Fracturing 101
Fracking chemicals
Potential for groundwater contamination
Fracking chemical disposal
Hydraulic fracturing best practices
Tips for landowners
Often an oil- or gas-bearing formation may contain large quantities of oil or gas, but have a poor flow rate due to low permeability, or from damage or clogging of the formation during drilling.[1] This is particularly true for tight sands, oil shales and coalbed methane. Hydraulic fracturing (also known as fracking, which rhymes with cracking) is a technique used to create fractures that extend from the well bore into rock or coal formations. These fractures allow the oil or gas to travel more easily from the rock pores, where the oil or gas is trapped, to the production well. [2] Typically, in order to create fractures a mixture of water, proppants (sand or ceramic beads) and chemicals is pumped into the rock or coal formation.
Hydraulic Fracturing Operation
Click here for larger view
Eventually, the formation will not be able to absorb the fluid as quickly as it is being injected. At this point, the pressure created causes the formation to crack or fracture. The fractures are held open by the proppants, and the oil or gas is then able to flow through the fractures to the well.[3] Some of the fracturing fluids are pumped out of the well and into surface pits or tanks during the process of extracting oil, gas and any produced water, but studies have shown that anywhere from 20-40% of fracing fluids may remain underground.[4]
Acidizing involves pumping acid (usually hydrochloric acid), into the formation. The acid dissolves some of the rock material so that the rock pores open and fluid flows more quickly into the well. Fracking and acidizing are sometimes performed simultaneously, in an acid fracture treatment. [5]
Hydraulic Fracturing - Issues and Impacts
Chemicals in Fracking Fluids. Source: EPA. Click here for a larger version.
Hydraulic Fracturing Chemicals - Coalbed fracture treatments use anywhere from 50,000 to 350,000 gallons of various stimulation and fracturing fluids, and from 75,000 to 320,000 pounds of proppant during the hydraulic fracturing of a single well.[6] Many fracturing fluids contain chemicals that can be toxic to humans and wildlife, and chemicals that are known to cause cancer. These include potentially toxic substances such as diesel fuel, which contains benzene, ethylbenzene, toluene, xylene, naphthalene and other chemicals; polycyclic aromatic hydrocarbons; methanol; formaldehyde; ethylene glycol; glycol ethers; hydrochloric acid; and sodium hydroxide.[7] Very small quantities of chemicals such as benzene, which causes cancer, are capable of contaminating millions of gallons of water.
Potential Groundwater Contamination - As mentioned previously, hydraulic fracturing is used in many coalbed methane (CBM) production areas. Some coal beds contain groundwater of high enough quality to be considered underground sources of drinking water (USDWs). According to the U.S. Environmental Protection Agency (EPA) ten out of eleven CBM basins in the U.S. are located, at least in part, within USDWs. Furthermore, EPA has determined that in some cases, hydraulic fracturing chemicals are injected directly into USDWs during the course of normal fracturing operations.[8] (Read stories by Peggy Hocutt and Laura Amos to learn how hydraulic fracturing of coalbeds and other geological formations has affected their lives.)
Frac Pit.
Calculations performed by EPA show that at least nine hydraulic fracturing chemicals may be injected into or close to USDWs at concentrations that pose a threat to human health. These chemicals may be injected at concentrations that are anywhere from 4 to almost 13,000 times the acceptable concentration in drinking water.[9]
Not only does the injection of these chemicals pose a short-term threat to drinking water quality, it is quite possible that there could be long-term negative consequences for USDWs from these fracturing fluids. According to the EPA study, and studies conducted by the oil and gas industry, [10] between 20 and 40% of the fracturing fluids may remain in the formation, which means the fluids could continue to be a source of groundwater contamination for years to come.
The potential long-term consequences of dewatering and hydraulic fracturing on water resources have been summed up by professional hydrogeologist who spent 32 years with the U.S. Geological Survey:
At greatest risk of contamination are the coalbed aquifers currently used as sources of drinking water. For example, in the Powder River Basin (PRB) the coalbeds are the best aquifers. CBM production in the PRB will destroy most of these water wells; BLM predicts drawdowns...that will render the water wells in the coal unusable because the water levels will drop 600 to 800 feet. The CBM production in the PRB is predicted to be largely over by the year 2020. By the year 2060 water levels in the coalbeds are predicted to have recovered to within 95% of their current levels; the coalbeds will again become useful aquifers. However, contamination associated with hydrofracturing in the basin could threaten the usefulness of the aquifers for future use. [11]
One potentially frustrating issue for surface owners is that it may not be easy to find out what chemicals are being used during the hydraulic fracturing operations in your neighborhood. According to the Natural Resources Defense Council, attempts by various environmental and ranching advocacy organizations to obtain chemical compositions of hydraulic fracturing fluids have not been successful because oil and gas companies refuse to reveal this "proprietary information." [12]
As mentioned above, anywhere from 20-40% of fracing fluids remain in the ground. Some fracturing gels remain stranded in the formation, even when companies have tried to flush out the gels using water and strong acids. [13] Also, studies show that gelling agents in hydraulic fracturing fluids decrease the permeability of coals, which is the opposite of what hydraulic fracturing is supposed to do (i.e., increase the permeability of the coal formations). Other similar, unwanted side effects from water- and chemical-based fracturing include: solids plugging up the cracks; water retention in the formation; and chemical reactions between the formation minerals and stimulation fluids. All of these cause a reduction in the permeability in the geological formations. [14]
Hydraulic Fracturing Chemical Disposal - When companies have an excess of hydraulic fracturing fluids, they either use them at another job or dispose of them. Some company Material Safety Data Sheets include information on disposal options for fracturing fluids and additives. The table below summarizes the disposal considerations that the company Schlumberger Technology Corp. ("Schlumberger") includes in its MSDSs. [15]
As seen in the table, Schlumberger recommends that many fracturing fluid chemicals be disposed of at hazardous waste facilities. Yet these same fluids (in diluted form) are allowed to be injected directly into or adjacent to USDWs. Under the Safe Drinking Water Act, hazardous wastes may not be injected into USDWs.[16] Moreover, even if hazardous wastes are diluted with water so that the hazardous characteristics of the fluids are removed, the wastes still cannot be injected into USDWs. If unused hydraulic fracturing fluids are indeed "hazardous wastes", it is unconscionable that EPA is allowing these substances to be injected directly into underground sources of drinking water.
Hydraulic Fracturing Best Practices
From a public health perspective, if hydraulic fracturing stimulation takes place, the best option is to fracture formations using sand and water without any additives, or sand and water with non-toxic additives. Non-toxic additives are being used by the offshore oil and gas industry, which has had to develop fracturing fluids that are non-toxic to marine organisms. [17]
It is common to use diesel in hydraulic fracturing fluids. This should be avoided, since diesel contains the carcinogen benzene, as well as other harmful chemicals such as naphthalene, toluene, ethylbenzene and xylene. According to the company Halliburton, "Diesel does not enhance the efficiency of the fracturing fluid; it is merely a component of the delivery system." [18] It is technologically feasible to replace diesel with non-toxic "delivery systems," such as plain water. According to the EPA, "Water-based alternatives exist and from an environmental perspective, these water-based products are preferable." [19]
Torn pit liners can lead to groundwater contamination.
Oil and gas wastes are often flowed back to and stored in pits on the surface. Often these pits are unlined. But even if they are lined, the liners can tear and contaminate soil and possibly groundwater with toxic chemicals. (Read more about pits.) As mentioned above, toxic chemicals are used during hydraulic fracturing operations. The same chemicals that are injected come back to the surface in the flowed-back wastes. As well, hydrocarbons from the fractured formation may flow back into the waste pits. A preferable way of storing wastes would be to flow them back into steel tanks.
Tips for Landowners
Obtaining fracking chemical information: The law requires that all employees have access to a Material Safety Data Sheet (MSDS), which contains information on health hazards, chemical ingredients, physical characteristics, control measures, and special handling procedures for all hazardous substances in the work area. The MSDSs are produced and distributed by the chemical manufacturers and distributors. It should be noted that MSDSs may not list all of the chemicals or chemical constituents being used (if they are trade secrets). [20] Landowners may be able to obtain copies of MSDSs from company employees, the chemical manufacturers, or possibly from state agency representatives.
Fracking chemicals
Potential for groundwater contamination
Fracking chemical disposal
Hydraulic fracturing best practices
Tips for landowners
Often an oil- or gas-bearing formation may contain large quantities of oil or gas, but have a poor flow rate due to low permeability, or from damage or clogging of the formation during drilling.[1] This is particularly true for tight sands, oil shales and coalbed methane. Hydraulic fracturing (also known as fracking, which rhymes with cracking) is a technique used to create fractures that extend from the well bore into rock or coal formations. These fractures allow the oil or gas to travel more easily from the rock pores, where the oil or gas is trapped, to the production well. [2] Typically, in order to create fractures a mixture of water, proppants (sand or ceramic beads) and chemicals is pumped into the rock or coal formation.
Hydraulic Fracturing Operation
Click here for larger view
Eventually, the formation will not be able to absorb the fluid as quickly as it is being injected. At this point, the pressure created causes the formation to crack or fracture. The fractures are held open by the proppants, and the oil or gas is then able to flow through the fractures to the well.[3] Some of the fracturing fluids are pumped out of the well and into surface pits or tanks during the process of extracting oil, gas and any produced water, but studies have shown that anywhere from 20-40% of fracing fluids may remain underground.[4]
Acidizing involves pumping acid (usually hydrochloric acid), into the formation. The acid dissolves some of the rock material so that the rock pores open and fluid flows more quickly into the well. Fracking and acidizing are sometimes performed simultaneously, in an acid fracture treatment. [5]
Hydraulic Fracturing - Issues and Impacts
Chemicals in Fracking Fluids. Source: EPA. Click here for a larger version.
Hydraulic Fracturing Chemicals - Coalbed fracture treatments use anywhere from 50,000 to 350,000 gallons of various stimulation and fracturing fluids, and from 75,000 to 320,000 pounds of proppant during the hydraulic fracturing of a single well.[6] Many fracturing fluids contain chemicals that can be toxic to humans and wildlife, and chemicals that are known to cause cancer. These include potentially toxic substances such as diesel fuel, which contains benzene, ethylbenzene, toluene, xylene, naphthalene and other chemicals; polycyclic aromatic hydrocarbons; methanol; formaldehyde; ethylene glycol; glycol ethers; hydrochloric acid; and sodium hydroxide.[7] Very small quantities of chemicals such as benzene, which causes cancer, are capable of contaminating millions of gallons of water.
Potential Groundwater Contamination - As mentioned previously, hydraulic fracturing is used in many coalbed methane (CBM) production areas. Some coal beds contain groundwater of high enough quality to be considered underground sources of drinking water (USDWs). According to the U.S. Environmental Protection Agency (EPA) ten out of eleven CBM basins in the U.S. are located, at least in part, within USDWs. Furthermore, EPA has determined that in some cases, hydraulic fracturing chemicals are injected directly into USDWs during the course of normal fracturing operations.[8] (Read stories by Peggy Hocutt and Laura Amos to learn how hydraulic fracturing of coalbeds and other geological formations has affected their lives.)
Frac Pit.
Calculations performed by EPA show that at least nine hydraulic fracturing chemicals may be injected into or close to USDWs at concentrations that pose a threat to human health. These chemicals may be injected at concentrations that are anywhere from 4 to almost 13,000 times the acceptable concentration in drinking water.[9]
Not only does the injection of these chemicals pose a short-term threat to drinking water quality, it is quite possible that there could be long-term negative consequences for USDWs from these fracturing fluids. According to the EPA study, and studies conducted by the oil and gas industry, [10] between 20 and 40% of the fracturing fluids may remain in the formation, which means the fluids could continue to be a source of groundwater contamination for years to come.
The potential long-term consequences of dewatering and hydraulic fracturing on water resources have been summed up by professional hydrogeologist who spent 32 years with the U.S. Geological Survey:
At greatest risk of contamination are the coalbed aquifers currently used as sources of drinking water. For example, in the Powder River Basin (PRB) the coalbeds are the best aquifers. CBM production in the PRB will destroy most of these water wells; BLM predicts drawdowns...that will render the water wells in the coal unusable because the water levels will drop 600 to 800 feet. The CBM production in the PRB is predicted to be largely over by the year 2020. By the year 2060 water levels in the coalbeds are predicted to have recovered to within 95% of their current levels; the coalbeds will again become useful aquifers. However, contamination associated with hydrofracturing in the basin could threaten the usefulness of the aquifers for future use. [11]
One potentially frustrating issue for surface owners is that it may not be easy to find out what chemicals are being used during the hydraulic fracturing operations in your neighborhood. According to the Natural Resources Defense Council, attempts by various environmental and ranching advocacy organizations to obtain chemical compositions of hydraulic fracturing fluids have not been successful because oil and gas companies refuse to reveal this "proprietary information." [12]
As mentioned above, anywhere from 20-40% of fracing fluids remain in the ground. Some fracturing gels remain stranded in the formation, even when companies have tried to flush out the gels using water and strong acids. [13] Also, studies show that gelling agents in hydraulic fracturing fluids decrease the permeability of coals, which is the opposite of what hydraulic fracturing is supposed to do (i.e., increase the permeability of the coal formations). Other similar, unwanted side effects from water- and chemical-based fracturing include: solids plugging up the cracks; water retention in the formation; and chemical reactions between the formation minerals and stimulation fluids. All of these cause a reduction in the permeability in the geological formations. [14]
Hydraulic Fracturing Chemical Disposal - When companies have an excess of hydraulic fracturing fluids, they either use them at another job or dispose of them. Some company Material Safety Data Sheets include information on disposal options for fracturing fluids and additives. The table below summarizes the disposal considerations that the company Schlumberger Technology Corp. ("Schlumberger") includes in its MSDSs. [15]
As seen in the table, Schlumberger recommends that many fracturing fluid chemicals be disposed of at hazardous waste facilities. Yet these same fluids (in diluted form) are allowed to be injected directly into or adjacent to USDWs. Under the Safe Drinking Water Act, hazardous wastes may not be injected into USDWs.[16] Moreover, even if hazardous wastes are diluted with water so that the hazardous characteristics of the fluids are removed, the wastes still cannot be injected into USDWs. If unused hydraulic fracturing fluids are indeed "hazardous wastes", it is unconscionable that EPA is allowing these substances to be injected directly into underground sources of drinking water.
Hydraulic Fracturing Best Practices
From a public health perspective, if hydraulic fracturing stimulation takes place, the best option is to fracture formations using sand and water without any additives, or sand and water with non-toxic additives. Non-toxic additives are being used by the offshore oil and gas industry, which has had to develop fracturing fluids that are non-toxic to marine organisms. [17]
It is common to use diesel in hydraulic fracturing fluids. This should be avoided, since diesel contains the carcinogen benzene, as well as other harmful chemicals such as naphthalene, toluene, ethylbenzene and xylene. According to the company Halliburton, "Diesel does not enhance the efficiency of the fracturing fluid; it is merely a component of the delivery system." [18] It is technologically feasible to replace diesel with non-toxic "delivery systems," such as plain water. According to the EPA, "Water-based alternatives exist and from an environmental perspective, these water-based products are preferable." [19]
Torn pit liners can lead to groundwater contamination.
Oil and gas wastes are often flowed back to and stored in pits on the surface. Often these pits are unlined. But even if they are lined, the liners can tear and contaminate soil and possibly groundwater with toxic chemicals. (Read more about pits.) As mentioned above, toxic chemicals are used during hydraulic fracturing operations. The same chemicals that are injected come back to the surface in the flowed-back wastes. As well, hydrocarbons from the fractured formation may flow back into the waste pits. A preferable way of storing wastes would be to flow them back into steel tanks.
Tips for Landowners
Obtaining fracking chemical information: The law requires that all employees have access to a Material Safety Data Sheet (MSDS), which contains information on health hazards, chemical ingredients, physical characteristics, control measures, and special handling procedures for all hazardous substances in the work area. The MSDSs are produced and distributed by the chemical manufacturers and distributors. It should be noted that MSDSs may not list all of the chemicals or chemical constituents being used (if they are trade secrets). [20] Landowners may be able to obtain copies of MSDSs from company employees, the chemical manufacturers, or possibly from state agency representatives.
About Hydraulic Fracturing for Oil and Gas
About Hydraulic Fracturing Oil and Gas
Hydraulic fracturing, commonly referred to as fracking, is a proven technological advancement which allows natural gas and oil producers to safely recover natural gas and oil from deep shale formations. This discovery has the potential to not only dramatically reduce our reliance on foreign fuel imports, but also to significantly reduce our national carbon dioxide (CO2) emissions and accelerate our transition to a carbon-light environment. Simply put, deep shale gas and oil formation development is critical to America's energy needs and economic renewal.Experts have known for years that natural gas and oil deposits existed in deep shale formations, but until recently the vast quantities of natural gas and oil in these formations were not thought to be recoverable. Today, through the use of hydraulic fracturing, combined with sophisticated horizontal drilling, extraordinary amounts of deep shale natural gas and oil from across the United States are being safely produced.
Hydraulic fracturing has been used by the natural gas and oil industry since the 1940s and has become a key element of natural gas development worldwide. In fact, regardless of whether they are vertical or horizontal wells, this process is used in nearly all natural gas and oil wells drilled in the U.S. today. Properly conducted modern hydraulic fracturing is a safe, sophisticated, highly engineered and controlled procedure.
http://www.netl.doe.gov/technologies/oil-gas/publications/EPreports/Shale_Gas_Primer_2009.pdf.
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