What chemicals are used in the hydraulic fracturing process?
Hydraulic fracturing involves pumping fracturing fluid into oil and gas wells at high pressure in order to fracture underground rock formations and release the hydrocarbons within. Fracturing fluid contains a combination of chemicals to reduce friction, prevent the growth of microorganisms, and prevent corrosion and damage to the wellbore and pipes. According to an EPA analysis of operator disclosures to FracFocus, chemical additives generally make up less than 1% by mass of the fluid; approximately 88% by mass is water. 1 The remainder of the mixture (approximately 10% by mass) consists of a proppant – usually silica sand – which is added to the fluid to hold open the fractures created in the shale formation and allow the oil or gas to flow.
The chemical components of the fracturing fluid vary, depending on the company and the characteristics of the well site. (See Table 4 for a list of common components in fracturing fluid and their uses.) The EPA analysis found that a median of 14 additive ingredients were used in fracturing fluids, ranging from 4 to 28 ingredients (5th to 95th percentile), but there were only a few ingredients that appeared in more than half the disclosures. 2 Some of the potential fracturing fluid additives are known to be toxic to mammals and harmful to human health, even at very low doses. 3, 4 In order to determine risks to human health, potential exposures, and exposure pathways need to be taken into account. In light of the diversity of fracturing fluid composition, the EPA study noted the importance of considering specific company practices at the local level. 5
The FracFocus website, a joint initiative of the Groundwater Protection Council and the Interstate Oil and Gas Compact Commission, encourages companies to disclose the chemicals used in fracturing fluid. Initially voluntary, by late 2013 companies in 14 states were required to report the chemicals used in their shale development operations on FracFocus. 6 Another 6 states imposed some level of disclosure requirements, and this area of legislation continues to evolve. The EPA analysis notes that its assessment of FracFocus disclosures was limited in part by the designation of some of fracturing fluid ingredients as confidential business information (CBI). Over 70% of the disclosures reviewed in the study contained at least one ingredient designated as CBI. 7 The operator practice of claiming some fracturing fluids as confidential information has caused some stakeholders to assert the information on FracFocus is incomplete and/or unreliable.
Finally, some companies have developed “green” fracturing fluids that reduce the volume of water required and/or replace some of the toxic chemicals with safer ones, including eco-friendly biocides. 8, 9, 10 These green alternatives may become more widely used as the technology improves and the price drops, particularly in areas where freshwater supplies are limited. 11
What happens to the fracturing fluid after it is pumped into the well?
Once the fracturing fluid has been injected into the shale formation, some of it returns to the surface as flowback. The amount of flowback returning varies widely depending on the geologic characteristics of the formation, ranging from 30% to 70% of the original volume, 12 while the remaining portion of the injected fluid remains trapped in the shale. After it interacts with the existing water and minerals in the target formation and the wellbore, the composition of the injected fluid changes. When the flowback returns to the surface, it can contain total dissolved solids (TDS), heavy metals, volatile organic compounds (VOCs), and naturally occurring radioactive material (NORM) from the deep rock strata (See Box 8. Focus on Naturally Occurring Radioactive Material) . Most of the flowback emerges in the first two weeks after hydraulic fracturing has taken place. After that, a small amount of fluid, referred to as produced water, continues to flow from the well along with the oil or gas during production. Produced water is the naturally occurring fluid present in the target formation (see Box 7. Components of Produced Water). For the purposes of this guidebook, we will hereafter refer to both types of water flowing from the well as produced water.
Box 7. Components of Produced Water
The water in the target geologic formation, which comes up to the surface as a component of hydraulic fracturing wastewater, can contain the following constituents:
How is wastewater handled?
There are several options for the management and disposal of well site wastewater, which includes produced water. First, it is temporarily stored at the site, either in open pits (which may or may not have a protective liner) or tanks. The industry is increasingly moving toward the use of tanks because the risk of wastewater seeping into the groundwater is greater with open pits. Furthermore, open pits can overflow during periods of heavy rains, allowing the wastewater to enter surface waters; wastewater in the pits can also evaporate, introducing pollutants into the air. With tanks, it is easier to detect and plug any leaks. On the other hand, tanks are more likely to have catastrophic failures, leading to the release of all their contents. For this reason, tanks are often surrounded by a secondary containment. 13 Many states require secondary containments, but most have yet to set standards for tank materials, which can also be a concern. 14 For example, produced water may corrode uncoated steel over time.
Some companies recycle the wastewater for reuse in their fracturing operations and other uses. One method of disposal is to inject the wastewater in deep underground wells, which are isolated from water sources by thousands of feet of impermeable rock. These wells are permitted under the Underground Injection Control (UIC) program, which is regulated under the Safe Drinking Water Act (SDWA). There are six categories (or classes) of UIC injection wells; the oil and gas industry uses Class II injection wells to 1) permanently dispose of wastewater or 2) reinject it at the site of a production well in order to improve the recovery of the resource (see Figure 3). This method of disposal is more common in states where the underlying geology is favorable.
The wastewater could also be transported by truck or pipeline to a municipal treatment facility that is permitted to process industrial waste and drilling wastewater, either nearby or in another state. Questions have been raised, however, as to whether municipal treatment facilities have the capacity to handle the volume and type of wastewater generated by shale operations, and some facilities have refused to accept wastewater from shale operations. 15, 16 The wastewater could also be processed at a private industrial treatment facility that conforms to the same or similar regulatory requirements as the public treatment plants. Finally, depending on the treatment process, the wastewater can also be recycled for use in other industrial operations, as irrigation water, or even as drinking water.
Source: Independent Petroleum Association of America, “Induced Seismicity.”
How is wastewater containing NORM handled?
If the levels of NORM (see Box 8. Focus on Naturally Occurring Radioactive Material) in the wastewater exceed standards set by state regulations or by OSHA for exposure risks, the operator is required to take it to a facility licensed to process such waste. Companies must comply with the Resource Conservation and Recovery Act (RCRA) standards for hazardous waste. 17 If the NORM levels are lower than those standards, then the wastewater can be disposed of using the methods described above for wastewater from oil and gas operations.
Could the water resources in my community be exposed to hazardous chemicals?
The principal pathway for the chemicals and other contaminants involved in shale development to enter local waterways is through improper management and disposal of wastewater or spills. Containment ponds, impoundments, and tanks can leak, allowing wastewater to enter surface and groundwater. Accidents involving the trucks transporting wastewater or other hazardous materials can result in spills, as can faulty equipment and human error. Additional water quality degradation may result from increased sedimentation caused by the construction of well pads and use of unpaved roads.
Determining the frequency of spills can be difficult because there is no national reporting system for oil and gas industry spills and other incidents, although state and federal regulations require reporting to states under certain circumstances. One EPA analysis of available data from 11 states from the period from 2006 to 2012 identified 457 spills at hydraulic fracturing well pad sites. 18 Low-volume spills (up to 1,000 gallons) were the most common, with relatively few high-volume spills (20,000 gallons or more). Produced water was the material most frequently spilled, usually due to human error. The incidents most often took place at storage units. The study found that the spilled material came into contact with the environment in over half the incidents, mostly with the soil, although in 33 cases the fluid reached surface or groundwater. Operators are required to have procedures and systems in place to properly manage any incidents or spills that might occur.
Some have expressed concern about another pathway for the chemicals involved in shale development to reach water resources – the possibility of fracturing fluid or other contaminants migrating into underground aquifers during the hydraulic fracturing process. The Geological Society of America notes that thus far there are possibly two such cases, and in one of them the fracturing operation was within 420 feet of the aquifer. 19 In general, fracturing activities are isolated from groundwater sources by thousands of feet of impermeable rock, 20 although wells must be drilled through usable groundwater in order to reach shale formations below. At groundwater depths, wellbores are encased in multiple thick layers of steel casing and concrete in order to prevent communication between the wellbore and water resources. Groundwater can become contaminated, however, if this protective casing and cement fails due to poor construction, and there have been instances of this occurring. 21 It is also possible that drilling the shallow section of a new well could allow for temporary communication between subsurface contaminants and groundwater resources before the well is cased.
It can be difficult to ascertain whether shale development operations have adversely affected local water supplies, largely because 1) baseline studies are not often performed and 2) many basins can naturally contain some of the hydrocarbons and metals accompanying shale development, such as methane. Nonetheless, the current scientific evidence indicates it is much more likely for leaks and spills to lead to surface water contamination than for the drilling and hydraulic fracturing of a well to cause groundwater contamination. 22
The U.S. EPA has been studying the potential impact of shale development operations on drinking water resources, and released a draft assessment summarizing existing science and new EPA research in June 2015. 23 This external review draft concludes that although there are mechanisms through which shale development could impact drinking water resources, the study team did not find evidence of widespread, systemic impacts on U.S. drinking water supplies. It notes that the failure to detect such drinking water impacts could be due to 1) the absence of impacts on a nationwide scale or 2) insufficient and/or unavailable data.
Finally, emerging technologies might help to resolve some questions around water quality. There are efforts underway to develop tracers for fracturing fluids, which could help determine the fluid’s fate in the environment. 24
- U.S. Environmental Protection Agency (EPA) Office of Research and Development (ORD), “Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0” (Washington, DC: March 2015), 62. ↩
- U.S. EPA ORD, “Analysis of Hydraulic Fracturing Fluid Data,” 63. ↩
- American Chemical Society, “A new look at what’s in “fracking” fluids raises red flags” (August 13, 2014). ↩
- U.S. House of Representatives, Committee on Energy and Commerce, Minority Staff, “Chemicals Used in Hydraulic Fracturing” (April 2011), 1-2. ↩
- U.S. EPA ORD, “Analysis of Hydraulic Fracturing Fluid Data,” 65-66. ↩
- U.S. Department of Energy, “Secretary of Energy Advisory Board Task Force Report on FracFocus 2.0” (Washington, DC: March 28, 2014), 9. ↩
- U.S. EPA ORD, “Analysis of Hydraulic Fracturing Fluid Data,” 63- 64. ↩
- Patrick J. Kiger, “Green Fracking? 5 Technologies for Cleaner Shale Energy,” National Geographic Daily News, March 19, 2014 ↩
- Apache Corporation, “Greener Chemicals,” accessed October 3, 2015 ↩
- Nathaniel Gronwold, “Entrepreneurs Turn to Bacteria to Fight Fracking Corrosion,” (July 3, 2014), Energywire. ↩
- Kiger, “Green Fracking?” ↩
- U.S. DOE, Modern Shale Gas, Development in the United States: A Primer (2009), 66. ↩
- Ground Water Protection Council (GWPC), “State Oil & Gas Regulations Designed to Protect Water Resources” (2014), 11 ↩
- GWPC, “State Oil and Gas Regulations,” 11. ↩
- Adgate, Goldstein, and McKenzie, “Potential Public Health Hazards,”8313. ↩
- Geological Society of America, “Hydraulic Fracturing,” 12. ↩
- U.S. Environmental Protection Agency Office of Water, A Regulators’ Guide to the Management of Radioactive Residuals from Drinking Water Treatment Technologies (Washington, DC: 2005). ↩
- The study authors note that this number is likely an under-estimate of total spills rated to shale development due to the difficulty of distinguishing them from other types of spills in the oil and gas sector and to incomplete data. The study also only took spills at well pad sites into account. U.S. Environmental Protection Agency Office of Research and Development, Review of State and Industry Spill Data: Characterization of Hydraulic Fracturing-Related Spills (Washington, DC: May 2015), 27. ↩
- Geological Society of America, “Hydraulic Fracturing,” 10. ↩
- An EPA analysis of disclosures to FracFocus found a median well depth of 8,100 feet, with a range of 2,900 to 13,000 feet (5th to 95th percentile). ↩
- Paleontological Research Institution, “Water: Out of the Wells,” Marcellus Shale 8 (November 2011), 10 ↩
- Adgate, Goldstein, and McKenzie, “Potential Public Health Hazards,” 8312. ↩
- U.S. Environmental Protection Agency Office of Research and Development, Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources: Executive Summary (External Review Draft) (Washington, DC: June 2015), ES-6. At the time of release of this guidebook, the EPA’s draft assessment is under review by the Science Advisory Board and is market as not for citation. For this reason, other than mentioning the report’s preliminary main conclusions, we are not drawing on any further details from this report in this version of the guidebook. ↩
- Dave Levitan, “Algae in Glass Cases Could Determine Fracking’s Toll,” Scientific American (March 6, 2014). ↩