Hydraulic Fracturing Process
After a well is drilled, the casing is perforated, typically with explosive charges. A “pad” of fluids is then injected, at a sufficient pressure and rate, to fracture the formation surrounding the perforations. The fractured formations are typically located thousands are feet below the water table. . Next, producers inject a “slurry,” which consists of fracing fluids and proppant, to extend and develop the fracture. Proppants are generally either sand, resin-coated sand, or ceramic. Finally, the fluid is removed from the well. A portion of the proppant remains trapped in the formation, which keeps the fractures open and allows gas to flow. See this video for an animation of the hydraulic fracturing process.
According to the American Petroleum Institute’s Hydraulic Fracturing Primer, hydraulic fracturing fluids generally consist of 90% water, 9.5% sand, and 0.5% chemicals. An average hydraulic fracturing job uses 3-7 million gallons of water, equating to 150,000 - 350,000 gallons of chemicals per well. The chemicals are used to enhance fracturing, in part by reducing friction, and to protect the well integrity. 750 different chemicals were used by the oil and gas industry for hydraulic fracturing between 2005 and 2009. For a list of the chemicals, see “Chemicals Used in Hydraulic Fracturing,” prepared by the United States House of Representatives Committee on Energy and Commerce. Diesel fuel, which is a carcinogen, is sometimes still a component of fracing fluids, but its use is increasingly discouraged. As is discussed in the State Rules section, some states now require that companies disclose the chemicals used to fracture a well. In addition, some companies voluntarily disclose the chemicals used. For example, Halliburton has disclosed the chemicals it uses for hydraulic fracturing in Colorado. Lastly, there is an effort within the oil and gas industry to develop more environmentally friendly fracing fluids.
Picture courtesy of National Energy Board (Canada)
Unconventional hydraulic fracturing uses more water than conventional hydraulic fracturing. Conventional hydraulic fracturing of vertical wells is referred to as “low-volume” hydraulic fracturing because less than 80,000 gallons of water are used to frac a single well. Unconventional hydraulic fracturing is referred to as “high-volume” hydraulic fracturing because 3-7 million gallons of water are typically used to frac a well. Larger volumes of water are required because unconventional wells are deeper and require higher pressures than conventional vertical wells. Fracing of unconventional wells may also be referred to as “high-volume slick-water hydraulic fracturing,” to include a reference to the chemical additives used.
Hydraulic Fracturing Controversy: Value versus Risks
High-volume slick-water hydraulic fracturing, together with the increasing cost of energy, allows for the economical recovery of natural gas from unconventional resources, which have a much lower permeability and flow capacity than conventional resources. The Energy Information Administration estimates that because of hydraulic fracturing, the U.S possesses natural gas resources sufficient to supply the U.S. for approximately 110 years and that shale gas will constitute 45% of the total U.S. natural gas supply in 2035. In addition, due to fracing, an estimated 7 billion barrels of oil are now thought to be recoverable.
Domestic natural gas production is encouraged to reduce dependency on foreign oil and is often seen as a “bridge fuel" to a more renewable energy-based economy because natural gas emits less carbon dioxide per unit of energy than other fossil fuels. Natural gas also requires less processing than petroleum. While a recent study found that the greenhouse gas footprint of natural gas is higher than that of conventional oil and gas and coal, due to fugitive methane emissions, a Department of Energy study found that, when compared to coal, the natural gas lifecycle results in one-half the equivalent carbon dioxide emissions.
Photo courtesy of FuelFix.com
This section discusses the risks attributable to shale gas development, instead of just the hydraulic fracturing process itself. Environmental and public health concerns include ground water contamination, increased traffic and industrial activity, accidents related to improper chemical handling, surface spills, waste disposal, air quality, and water use.
Groundwater Contamination from Below-Ground Activity
There are indications (see, for example, the EPA’s study in Pavillion, Wyoming and reports of contamination in Colorado) that the hydraulic fracturing process has caused the groundwater near drilling sites to become contaminated with fracing chemicals, natural gas, or biogenic methane. But in many cases, a lack of baseline sampling has prevented landowners from proving whether alleged contamination is connected to hydraulic fracturing.
Whether hydraulic fracturing fluids can migrate from the fracing site to drinking water aquifers is highly disputed, in part because the fractured shale is generally separated from groundwater by thousands of feet of impermeable rock strata, and in part due to a lack of peer-reviewed research. However, improper casing or cementing, poor production pressure management, or drilling in a geologically unstable location can allow fracing fluids to migrate into drinking water supplies. Duke researchers discovered that concentrations of thermogenic methane, with a chemical signature consistent with deep shale thermogenic methane sources, increase with proximity to natural gas wells in Pennsylvania. It is currently unknown whether improper drilling techniques or conduits between the fractured shale and ground-water resources caused the contamination. In addition, due to a lack of baseline sampling, it is possible that this thermogenic methane is present naturally.
Groundwater Contamination from Above-Ground Activity
“Leaks from produced water impoundments and spills, from for example trucks hauling returned water or hydraulic fracturing fluids, can cause contamination. Truck traffic can also contribute to erosion and sediment contamination of groundwater, and the EPA estimates that 1 acre of construction site with no runoff controls (including uncontrolled access roads) can contribute 35-45 tons of sediment each year, nearly 16 times the sediment of an acre of natural vegetated meadow. Runoff from natural gas projects may also contain pollutants from contact with the equipment or with fracking fluid and produced water storage facilities. Currently, many believe this above-ground activity is a greater threat to drinking water resources than below-ground activity. For example, pits used for either storage or disposal of drilling wastes and returned water are believed to have contributed to the contamination in Pavillion, Wyoming.
As such, disposal of fracing waste water is a concern. Disposal typically occurs using either permitted disposal wells or waste water treatment plants, or by evaporation, which occurs in pits. Because oil and gas waste is exempt from hazardous waste regulations, it can be disposed of in class II wells rather than in Class I hazardous waste wells, resulting in a greater risk of groundwater contamination. Waste water treatment plants may be unable to adequately treat produced water and higher levels of heavy metals and radioactivity are being reported in waste water treatment plant discharges.
According to a recent report by the Pacific Institute, Hydraulic Fracturing may create greater risks to our water supply than the injection of carcinogenic chemicals underground, such as surface spills and leaks, stormwater runoff, and truck traffic impacts on water quality. Visit the Pacific Institute website for the full report.
Water usage varies based on the depth of the well and the number of frac events. A typical well can use several million gallons of water. There is currently an effort within the industry to recycle returned water, either by reverse osmosis or other filtration/treatment techniques. While the water used to create the fracturing fluid can be recycled, the chemicals added to the fluid make the process more difficult by interfering with the reverse osmosis process. Specifically, the gelling agents (guar gum is the most common), that are used to prevent the fractures from collapsing, interfere with this process. But, a recent study conducted by Yaal Lester indicates that treating the flowback fluid with specific biologically activated fluids can help degrade these gelling agents prior to the reverse osmosis process, creating a better yield when recycling the fluid. In many Rocky Mountain areas, the industry has achieved 90-95% recycling of produced water.
However, much of the water used to fracture a well stays underground, so groundwater and stream depletion remains a concern in some areas as fresh water continues to be used for fracing. In addition, even when fracing water is reused, it may be necessary to dilute it with fresh water prior to reuse. And, while the EPA estimates 2.3-3.8 million gallons of water are used in the fracturing of each shale gas well, new data suggests this number can vary greatly by region, with operators in Texas’ Eagle Ford shale area using up to 13 million gallons of water per well for fracking alone. Furthermore, the water is typically withdrawn from one source over several days, and can have significant local impacts, especially if it is withdrawn from environmentally sensitive areas.
Additionally, with the rapid spread of Hydraulic Fracturing in the West and across the Nation, conflicts over water usage are emerging. In 2012 in Colorado, natural gas companies purchased at auction water rights that had previously been largely claimed by farmers, raising questions about the impacts of fracking on agriculture. Similarly, 2011 in Pennsylvania’s Susquehanna River Basin, 11 water withdrawal permits for natural gas projects were temporarily suspended due to low stream levels. As there was no draught in the basin, the lower stream levels suggest a conflict over limited water resources.
Well completion can result in significant air emissions. After a new well is drilled, operators need to remove fracing fluid and debris from the well bore and the formation. This is called the “flowback” stage. As fluids are removed from the well, large quantities of volatile organic compounds (VOCs), methane, and air toxics, such as benzene, are produced. Typically, the gases are vented or flared, which can lead to regional air quality problems. Green completions reduce gas losses during well completions. As is discussed in the Federal Regulatory section, green completions can reduce VOC emissions by 95%. In addition, green completions capture gas that can potentially be sold, resulting in increased revenue.
Additional sources of air emissions include engines used to move equipment and materials, drill wells, and pump fluids, and the materials pumped into the wells. The emissions may include combustion products, particulate matter, VOCs, methane, and air toxics. In June 2012, the Occupational Safety and Health Administration (OSHA) issued a hazard alert for hydraulic fracturing workers due to the potential danger of silica dust. The report Identified seven sources of silica dust exposure during fracking, and found that while transporting, moving, and refilling silica to be used as a fracking proppant, dust can be released into the air consisting of 99% silica. High exposure to silica creates a greater risk of silicosis, and can also cause cancer. OSHA recommends a combination of engineering controls, work practices, protective equipment and product substitution, and worker training to minimize the risk. The hazard alert is available on OSHA’s website.
Fracing is an industrial operation. Fracing operations require the shipment of fracing fluid and equipment to the fracing site. After arriving at the fracing site, the large number of tanker trucks, vehicles, and equipment typically necessitate approximately 1-2 acres surrounding the well site. The well drilling and subsequent fracing are also loud, and the noise, while temporary, can last from two weeks to over a month. Finally, the recovered gases and produced liquids, including hydrogen sulfide, are odorous and may result in complaints from nearby residents.
Hydraulic Fracturing BMPs
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Several entities, including the BLM, state agencies, and communities, recommend the use of BMPs for hydraulic fracturing. BMPs are generally recommended to address the handling of fracing fluids, reduce traffic and surface disturbances, and protect water quality.
In the News
The United States Government Accountability Office (GAO) released two reports on hydraulic fracturing in September 2012. In the first report, titled Oil and Gas: Informationon Shale Resources, Development, and Environmental and Public Health Risks, GAO investigated the size and growth of the shale gas industry as well as the environmental and public health
risks associated with shale gas development.
Some key findings of the report:
- Shale oil production increased more than five-fold from 2007 to 2011, and shale
gas production increased more than four-fold from 2007 to 2011.
- Energy Information Administration (EIA) estimates that the amount of technically
recoverable shale gas in the United States is 482 trillion cubic feet—an increase of
280 percent from EIA’s 2008 estimate.
- Oil and gas development, whether conventional or shale oil and gas, pose inherent environmental and public health risks, but the extent of these risks
associated with shale oil and gas development is unknown, in part, because the
studies GAO reviewed do not generally take into account the potential long-term,
The second report, titled Unconventional Oil and Gas Development: Key
Environmental and Public Health Requirements, describes federal and state regulatory requirements and identifies challenges that federal and state agencies
face in regulating unconventional gas development.
Some key findings of the report:
- Exemptions in federal regulatory coverage affect the applicability and might limit the effectiveness of environmental and public health laws.
- All of the state programs reviewed by GAO implement additional protective requirements for activities associated with oil and gas development.
- Federal and state agencies reported several challenges in regulating oil and gas development from unconventional reservoirs. EPA officials reported that
conducting inspection and enforcement activities and having limited legal
authorities are challenges. For example, conducting inspection and enforcement
activities is challenging due to limited information, such as data on groundwater
quality prior to drilling.
Oil and gas development is regulated by federal, state, and local governments. This section only discusses the laws and regulations that are directly related to hydraulic fracturing. For example, well casing regulations, while important for ensuring that fracing fluids do not migrate into groundwater, are generally applicable and are not discussed in this section. For information about the regulation of oil and gas development generally, see our Law and Policy Section.
Environmental Protection Agency (EPA)
The 2005 Energy Policy Act exempted the injection of fracing fluids from the Safe Drinking Water Act’s Underground Injection Control Program. (See our Federal Water Quality Laws and Regulations Section for more information about this program.)
The 2005 Energy Policy Act did allow the EPA to continue regulating the use of diesel fuel in fracing fluids. The EPA recently decided to begin requiring permits for the use of diesel fuel in fracing fluids, and has released a draft permitting guidance that is currently undergoing public notice and comment. Highlights of the guidance reccomendations include: suggested creation of submission timeframes by permit writers long enough to allow comprehensive consideration of all relevant permit information, suggested modification of the ¼ mile fixed radius approach to finding the area of review so as to account for directional drilling and multiple wells co-located on one well pad, and ensuring that surface casing and cement extend through the base of the lowermost underwater source of drinking water. For more information, please consult the EPA website, which includes a presentation related to underground injection control generally, and a presentation about the proposed permitting guidance.
The EPA is currently studying the potential impacts of hydraulic fracturing on water resources. The EPA released the final study plan in November 2011. As part of the study, EPA is conducting case studies. The EPA is conducting two prospective case studies, to monitor key aspects of the hydraulic fracturing process throughout the lifecycle of the well. In addition, the EPA is conducting five retrospective case studies in areas where hydraulic fracturing has already occurred. In these areas, the EPA seeks to determine whether hydraulic fracturing has impacted drinking water resources. One of the areas selected for retrospective case study is Las Animas County, Colorado, which is located in the Raton Basin. Initial results should be available in 2012 and a final report from the EPA study should be available in 2014.
In October 2011, the EPA announced it would develop new wastewater treatment standards for wastewater discharges produced from shale formations. The EPA stated that a "significant" amount of the wastewater produced must be treated (because it is not re-injected or reused) and that the EPA will develop standards "based on demonstrated, economically achievable technologies" that must be met before the wastewater goes to a treatment facility.
In April of 2012 the EPA finalized rule amendments revising the New Source Performance Standards for Volatile Organic Compounds from hydraulically fractured natural gas production wells, requiring reduction of VOC emissions by 95 percent and requiring this to be done through capture after January 2015. For a synopsis of the relevant rule amendments as well as a link to the Rule and EPA summaries, visit our page, 2012 EPA amendment of New Source Performance Standards.
Department of Energy (DOE) –
Hydraulic Fracturing Subcommittee
In 2009, the DOE published Modern Shale Gas Development in the United States: A Primer, which discusses the economics of shale gas development, the current regulatory framework, and environmental considerations.
In May 2011, the DOE formed a subcommittee of the Secretary of Energy’s Advisory Board to conduct a review of fracing and make recommendations to improve its safety and environmental performance. The subcommittee was comprised of environmental, industry, and state regulatory experts. The group released its 90-day interim report on August 18, 2011 and its final report on November 18, 2011. This report consists of “consensus based recommendations” to improve the safety and environmental performance of fracing. The final report calls for numerous improvements, including 1) increasing coordination between state and federal regulators, 2) improving air quality in the vicinity of oil and gas development, 3) increasing the use of best management practices, and 4) ensuring that water quality is protected.
Congress – FRAC Act
The Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”), which was originally introduced in both houses of Congress in June 2009, was reintroduced in the House of Representatives and the Senate in March 2011. The bill would eliminate the hydraulic fracturing exemption from the Safe Drinking Water Act and require public disclosure of the chemicals used in the hydraulic fracturing process.
Bureau of Land Management (BLM)
Drilling on federal land must comply with both BLM and state regulations. Currently the BLM does not require that drillers disclose the chemicals contained in hydraulic fracturing fluids, but recommends BMPs for limiting the environmental impacts of fracing (see Hydraulic Fracturing BMPs, below).
In May 2012, the Obama administration proposed national hydraulic fracturing regulations through the BLM. The proposed rule had three major components. First, it would have required public notification of the chemicals used in the fracking process within 30 days of the beginning of drilling a well. Second, the rule would have required well-bore integrity logs to make sure there are not leaks of fluids into water sources. Third, the rule would have required a water monitoring program to account for and monitor the large amounts of contaminated water that flow back from the hydraulic fracturing process.
However, in January 2013 the Obama administration scrapped this plan in hopes of imposing new mandates governing drilling on public lands. Interior Department spokesman Blake Androff confirmed the Bureau of Land Management would propose the new draft in spring 2013 after “making improvements . . . in order to maximize flexibility, facilitate coordination with state practices and ensure that operators on public lands implement best practices.” For current status information and development, visit the BLM Newsroom.
In May 2013, the BLM re-proposed updates to hydraulic fracturing on federal land. The proposed rule would apply to over 750 millions subsurface acres of federal and Indian mineral estate, including lands managed by the Forest Service and the Fish and Wildlife Service. The newly proposed rule affects three areas of hydraulic fracturing: chemical disclosure, well integrity, and flowback water management.
To read the full text of the BLM's proposed update to 43 CFR Part 3160, click here: BLM 2013 Supplemental Notice of Proposed Rulemaking & Request for Comment
For a concise fact sheet concerning the BLM's newly proposed rule, see here: BLM's Proposed Fracing Rule - July 2013
The Colorado Oil and Gas Conservation Commission (COGCC) requires operators to complete and post a chemical disclosure registry disclosing the chemicals used in hydraulic fracturing operations within 60 days of the conclusion of a hydraulic fracturing treatment, and never more than 120 days after the start of such a hydraulic fracturing treatment. If the specific identity or concentration of a chemical is claimed to be a trade secret it need not be disclosed, but this must be indicated on the disclosure form, and at least the chemical family or other similar descriptor must be included. However, the protected information must be provided to the COGCC if the director requests it by letter because it is necessary to respond to a spill or a complaint. Such information will only be made available to necessary parties, and will not be considered publically available. (COGCC Rule 205A). Chemical disclosures are available at FracFocus, but may not be available for wells drilled before April 1, 2012 when disclosure became required.
As was discussed in the Federal Regulatory Section, the EPA is proposing to require green well completions. Colorado already requires green well completions (COGCC Rule 805).
Colorado requires continuous monitoring and recording of the pressure in the bradenhead annulus and in the annulus between the intermediate casing and the production casing to ensure that fracing fluids are confined to the targeted formations (COGCC Rule 341). If elevated pressures are observed, which may indicate that fluid is leaking from the well, operators must notify the COGCC.
Colorado also requires baseline and post-completion surface water sampling if stimulation activities occur in a Surface Water Supply Area (COGCC Rule 317B).
Additional rules, applicable to hydraulic fracturing, can be found at this COGCC website and additional information about hydraulic fracturing in Colorado generally can be found at this COGCC website.
The State Review of Oil and Natural Gas Environmental Regulations (STRONGER), is a non-profit, multi-stake holder organization that assists states in documenting their environmental oil and gas development regulations, and comparing their regulatory programs against a set of national guidelines. A STRONGER review panel, which consisted of one industry representative, one state regulator, and one member of the environmental community, recently conducted a review of Colorado’s rules governing the hydraulic fracturing process. STRONGER issued a report, including recommended improvements to the COGCC rules.
The Montana Board of Oil and Gas Conservation (MBOGC) adopted new rules governing hydraulic fracturing, which became effective on August 26, 2011. Operators must generally obtain approval from the MBOGC before fracing occurs and submit a report of the actual work performed (MBOGC Rule 36.22.1010). In addition, operators must disclose the composition of the fracing fluids (if a trade secret exemption is not applicable) either to the MBOGC or through the FracFocus website (discussed below) or a similar website (MBOGC Rule 36.22.1015). Finally, the MBOGC mandates specific construction and testing requirements for wells that will be fraced (MBOGC Rule 36.22.1106).
The New Mexico Oil Conservation Division requires operators to complete and post a chemical disclosure registry disclosing the chemicals used in hydraulic fracturing operations within 45 days of the conclusion of a hydraulic fracturing treatment. Operators must disclose the total volume of fluid pumped, the maximum ingredient concentration in each additive, and the maximum ingredient concentration in the hydraulic fracturing fluid. However, if the specific identity or concentration of a chemical is claimed to be a trade secret, the division does not require the reporting or disclosure of the chemical. The rule can be found in the New Mexico Administrative Code 22.214.171.124.B.
Operators must notify the New Mexico Oil Conservation District (NMOCD) if fracing has damaged the well casing, casing seat, producing formation, or injection interval (19 N.M.A.C. 15.16.16). The operator must either repair the damage or plug and abandon the well.
New Mexico regulates the construction of pits, closed-loop systems, below-grade tanks, and sumps. (19 N.M.A.C. 15.17). These regulations were developed in response to above-ground contamination concerns associated with hydraulic fracturing. For additional information, see our summary of New Mexico Oil and Gas Regulations.
In Wyoming, Chapter 3 § 45 is specific to hydraulic fracturing. An approved application for a permit to drill is required before fracing can occur and casing integrity testing may be required (WOGCC Chapter 3 § 45(a)). The operator must provide the Wyoming Oil and Gas Conservation Commission (WOGCC) with a detailed description of the well stimulation design (WOGCC Chapter 3 § 45(e)) and the geologic formation (WOGCC Chapter 3 § 45(b)). During stimulation, the pressure in the bradenhead annulus and in the annulus between the intermediate casing the production casing must be continuously monitored (WOGCC Chapter 3 § 45(i)). If elevated pressures are observed, which may indicate that fluid is leaking from the well, the operator must notify the WOGCC.
The WOGCC requires disclosure of the types and amounts of chemicals used in fracing operations. Operators must submit data to the WOGCC prior to stimulation (WOGCC Chapter 3 § 45(d)); the WOGCC catalogs the data while maintaining the confidentiality of any proprietary information (WOGCC Chapter 3 § 45(f)). However, according to a memorandum issued by the WOGCC, § 45(f) will generally not afford confidentiality protection for well drilling, completion, or stimulation (2010 Memorandum).
The WOGCC also restricts the use of diesel and volatile organic compounds (VOCs) in hydraulic fracturing (WOGCC Chapter 3 § 45(g)).
Finally, the WOGCC requires a post-stimulation report, which must include information about the fracing conducted, including the amount of fluids used and several well parameters. (WOGCC Chapter 3 § 45(h)). The operator must also disclose whether fracing fluids are disposed or reused (WOGCC Chapter 3 § 45(j)).
As discussed above, the EPA is proposing to require green well completions. Wyoming already requires green well completions.
The city of Grand Junction and the neighboring town of Palisade developed a Watershed Plan with Genesis Gas and Oil (Genesis), which is not legally binding, but addresses citizens’ concerns about oil and gas development. The plan provides that Genesis will use “green” fracing fluids, release the names of the fracing fluid constituents, and inject a tracer with the fracing fluids so that any alleged contamination can be linked to its source. The original watershed plan was a voluntary, collaboratively created document. Grand Junction incorporated it by reference into its watershed ordinance, and now all operators in their watershed must abide by its provisions. More information about this watershed plan can be found on our Community Spotlight page.
The communities of Rifle, Silt, and New Castle developed a Community Development Plan with Antero Resources Corporation and Galaxy Energy, which is not legally binding, but aims to shape how natural gas development occurs in these communities. The plan (1) provides that the oil companies will conduct all hydraulic fracturing with “green” fracing methods and use closed-loop drilling systems; (2) prohibits the use of diesel, petroleum products, and chemicals containing aromatic compounds; and, (3) asks operators to ensure the safety of dams if fracturing takes place. More information about this community development plan can be found on our Community Spotlight page.
Santa Fe County adopted an Oil and Gas Ordinance in 2008. Section 11.25 is entitled “Fracturing and Anodizing.” The ordinance states that fracturing shall not create excess noise levels. In addition, fracturing can only use fresh water. For more information about Santa Fe County’s Oil and Gas Ordinance see our New Mexico County and Municipal Law page.