As most everyone who follows the news these days knows, the media’s frequent focus on hydraulic fracturing, or “fracking,” has caused the drilling practice to become extremely controversial, with passionate supporters and ardent opposition filling town halls across many states. The practice has been established as safe when done correctly. Like many activities, however, hydraulic fracturing and associated oil and gas development activities can be complicated by extreme weather conditions. This article will examine the risks posed by flooding and fracking, how regulations as currently written are capable of managing those risks, and how the industry can prepare itself for extreme weather events.
Fracking is not new. Well operators first began fracturing wells in Pennsylvania in the early 1860s. Hydraulic fracturing, which included the addition of water as a fracturing fluid, has existed in the United States since at least the 1940s. FracFocus, Chemical Disclosure Registry, A Historical Perspective. Hydraulic fracturing is not specific to natural gas or to the United States, and operators hydraulically fracture thousands of wells around the world every year. In fact, hydraulic fracturing has been used in more than one million producing wells. Id.
Despite a long history of successful hydraulic fracturing, the practice has become a hot topic in recent years as enhancements in gas well development technology—and specifically the combination of horizontal drilling and hydraulic fracturing—have made the exploration of unconventional gas sources not only possible, but also economical and have enabled the industry to develop resources that once were commercially unavailable. Experts believe 60 to 80 percent of all wells drilled in the United States over the next ten years will be hydraulically fractured. FracFocus, Chemical Disclosure Registry, Hydraulic Fracturing: The Process.
Although the media is quick to report on anecdotes of purported detrimental environmental impacts of fracturing, recent studies actually have shown no link between hydraulic fracturing and contamination of drinking water. For example, in early 2012, the U.S. Environmental Protection Agency (EPA) conducted water sampling and testing in the area of Dimock, Pennsylvania, which has been at the center of a fierce debate over the environmental and public health impacts of Pennsylvania’s Marcellus Shale drilling industry. On March 15, 2012, EPA announced that its tests demonstrated well water in Dimock has not been contaminated by hydraulic fracturing and that any chemicals found in the water there either were naturally occurring or were present in concentrations within the safe range for drinking water. Statement Released to Press Inquiries March 15, 2012. Subsequent tests performed by EPA in April 2012 confirmed earlier agency findings that the level of contaminants found in drinking water wells in Dimock do not exceed federal drinking water standards and do not pose a threat to human health and the environment. EPA, Dimock Week 1, 2, 3, 4 & 5. Similarly, on March 30, 2012, EPA agreed to end its lawsuit against Range Resources Corporation, which would have forced the company to modify natural gas wells the agency previously had alleged were contaminating water in Parker County, Texas. Following extensive investigations into the claims, which ultimately established no link between Range’s operations and water contamination, EPA withdrew an administrative order and joined with Range to seek dismissal of the case filed in federal court in Dallas. EPA, Notice of Withdrawal of Imminent and Substantial Endangerment Order, Docket No. SDWA-06-2011-1208 (Mar. 29, 2012); United States v. Range Prod. Co. and Range Resources Corp., Joint Stipulation of Dismissal Without Prejudice Pursuant to Fed. R. Civ. P. 41(a)(1)(iii) and (a)(1)(B), No. 3:11-CV-00116-F (N.D. Tex. Mar. 30, 2012).
Notably, public sentiment appears to coincide with EPA’s decisions in both Dimock and Parker County. A March 2012 poll conducted by Rasmussen found that 57 percent of Americans favor the use of hydraulic fracturing to develop natural resources, while just 22 percent said they oppose fracturing, and 21 percent said they were unsure about it. 57% Favor Use of “Fracking” to Find More U.S. Oil and Gas, Rasmussen Reports, Mar. 26, 2012.
The potential economic benefits of hydraulic fracturing are also vast. IHS Global Insight, which provides economic forecasts, analysis, and data for the United States and worldwide, estimated that natural gas from shale could create 870,000 jobs in the United States and add $118 billion to the national economy over the next four years and will contribute $933 billion in taxes over the next twenty-five years. Jim Efstathiou Jr., Shale-Gas Drilling to Add 870,000 Jobs by 2015, Report Says, Bloomberg, Dec. 6, 2011.
Although the economic benefits of hydraulic fracturing are far reaching, fears about potential environmental impacts have delayed the exploration and development of natural gas in shale formations in some states, most notably New York. As fracturing gains a foothold across much of the Appalachian region, with debates about the benefits and dangers taking place from upstate New York to North Carolina, people from all sides of the debate are taking a closer look at regulations and industry practices associated with drilling activities, including those related to the effects of extreme weather conditions. Extreme weather events, such as flooding, could pose an additional challenge for an industry that is already under heavy scrutiny.
In Texas and the Southwest, where the weather is generally dry and arid, industry typically employs natural pond evaporation to deal with gas wastewater. In the eastern United States, where heavy rains are a frequent concern, evaporation is generally not an option. The entire Appalachian region, which encompasses the coveted Marcellus and Utica shale plays, is laced with an extensive network of springs, streams, and rivers. Certain areas of Appalachia average around 47 inches of annual rainfall, with some areas regularly receiving between 69 and 90 inches—exceeded in the United States only by the northwest Pacific coast. As anyone who lives in the Appalachian region can attest, this rainfall frequently comes in extremely heavy downpours during short periods. Sudden rainfalls bring with them rapid rises in stream flows and the potential for treacherous floods.
Fracking and Flowback
Depending on the well site, hydraulic fracturing typically involves the injection of between 1 and 5 million gallons of water (with a propping agent, such as sand, and trace elements of chemicals) at high pressure down vertically as far as 10,000 feet below the surface and then across into horizontally drilled wells that can span thousands of feet in length. U.S. Department of Energy (DOE), Office of Fossil Energy, Oil and Natural Gas Program, State Oil and Natural Gas Regulations Designed to Protect Water Resources, May 2009 (hereinafter DOE Report). The pressurized fluid mixture causes the rock layer to crack. As the injection pressure is reduced, the natural pressure of the formation pushes the fluid (termed “flowback water”) back to the surface. Id. Typically, most of the original fracturing fluid is recovered during the initial flow back, although additional fracturing water, called “produced water,” is recovered along with gas after the well is put into production. The sand left behind props open the fractures, allowing natural gas within the shale to flow back up the well.
The additives contained in fracturing fluids serve specific functions. For example, in hydraulic fracturing of deep shale gas zones, the water is commonly mixed with a friction reducer to lessen the resistance of the fluid moving through the casing and biocides to prevent bacterial growth. DOE Report, p. 22. According to DOE, although a small number of possible fracture fluid additives have the potential to cause negative health effects at certain exposure levels, most additives such as sodium chloride, potassium chloride, and diluted acids present low to very low risks to human health and the environment. Id. at p. 22. Those chemicals with known adverse health effects cause the greatest concern should flooding or other extreme weather affect drilling operations.
Once hydraulic fracturing fluids return to the surface, they are typically stored in tanks or lined pits to isolate them from soils and shallow groundwater zones. The DOE Report, based on research conducted by the DOE’s Office of Fossil Energy, Oil and Natural Gas Program in conjunction with the National Energy Technology Laboratory and the Groundwater Protection Council, concluded that proper handling of fluids returned to the surface is crucial to safeguard the environment and humans from exposure to hydraulic fracturing fluids. Id. Thus, if the pits are located in a floodplain, care must be taken to assure proper storage and containment in case of heavy rains or flooding.
Management of the flowback water has become a major part of the shale gas controversy, both from the standpoint of possible uncontrolled releases and the treatment, recycling, and discharge of the waste. In February 2012, the Energy Institute at The University of Texas at Austin released a study finding that overall, surface spills of fracturing fluids pose greater risks to groundwater sources than hydraulic fracturing itself. The Energy Institute, The University of Texas at Austin, Fact-Based Regulation for Environmental Protection in Shale Gas Development, Feb. 2012. The research team examined evidence contained in reports of groundwater contamination attributed to hydraulic fracturing in three prominent shale plays—the Barnett Shale in North Texas, the Marcellus Shale in Pennsylvania, West Virginia, and New York, and the Haynesville Shale in western Louisiana and northeast Texas—and found that most problems ascribed to hydraulic fracturing are more likely the result of casing failures or poor cement jobs. Id. at p. 24. The researchers concluded that many reports of contamination could be traced to above-ground spills or other mishandling of wastewater produced from shale gas drilling, rather than from hydraulic fracturing per se. Id. at p. 65. In fact, there have been no confirmed cases of drinking water contamination as a result of fracturing. Id. at p. 19.
It is the potential for surface spills and mismanagement of wastewater that appear to create the greatest risk of improper discharge when combined with extreme weather events such as flooding. Since the first oil and gas wells were hydraulically fractured more than sixty years ago, pits have been used to hold drilling fluids and wastes. Today, excavated pits remain the most common means of storing fluids during drilling and well operations and are used for storage and evaporation of produced water, for emergency overflow, and for temporary storage of well completion and treatment fluids. DOE Report, p. 29. These pits range in size but have a typical volume of 750,000 gallons, according to the New York Department of Environmental Conservation (NYDEC). New York State Department of Environmental Conservation, Division of Mineral Resources, Draft Supplemental Generic EIS: Oil, Gas and Solution Mining Regulatory Program, Sept. 2009 (N.Y. Draft sGEIS), p. 5–99. An EPA study released in February 2011 notes that in New York, regulators are analyzing the use of centralized pits, or impoundments, with a capacity to store from 1 to 16 million gallons of flowback and serve well pads within a 4-square-mile area. EPA, Office of Research and Development, Draft Plans to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, 2011, p. 36.
Typically, pit liners are constructed of compacted clay or synthetic materials such polyethylene or treated fabric that is joined using special equipment such as a seam welder. DOE Report, p. 29. Although the use of a pit liner may be necessary to prevent infiltration of fluids into the subsurface, pit liners are not required in every state. Id. at p. 29–30. According to the DOE Report, for example, ten states require pits used for long-term storage of fluids to be placed a minimum distance from surface water to prevent potential overflows that could result in an unauthorized discharge to water. Id. Twelve states explicitly prohibit the use of pits that intersect the water table, and sixteen states require fluids in pits to remain a certain level below the top of the pit wall. Id. This required freeboard is intended to provide for a safety margin to prevent pit overflows in the event of significant rainfall. Id. Even if pit liners were required in every state, they would not prevent possible overflow or the runoff of stormwater caused by heavy rains or flooding absent proper management or location requirements.
In late 2010 in the state of New York, Governor Patterson signed an executive order instating a formal moratorium on the issuance of high volume, horizontal drilling permit applications, which was subsequently extended by Governor Cuomo. However, in light of the commercial success of hydraulic fracturing and the economic boom provided to areas that support its practice, New York is reconsidering its moratorium. In July 2011, the NYDEC issued a supplemental draft of its environmental impact statement (EIS) that directly addressed the issue of flooding and fracking. The NYDEC recommended that drilling should be prohibited (1) within 2,000 feet of public drinking water supplies, (2) on the state’s eighteen primary aquifers and within 500 feet of their boundaries, (3) within 500 feet of private wells, and (4) in floodplains. N.Y. Draft sGEIS.
Intense flooding in New York caused by Hurricane Lee in September 2011 reignited the debate over how best to manage and store fracking fluids and flowback water and, further, whether pits can adequately prevent overflow or stormwater runoff. In the southern tier of New York, along the Pennsylvania border, the area was inundated by record-high floodwaters, forcing the closure of major highways and washing out roads, bridges, and entire neighborhoods. Corey Kilgannon, Flooding Persists in Southern Tier of New York, N.Y. Times, Sept. 9, 2011. The Susquehanna River broke a flood record and began flowing over retaining walls in parts of New York, and on September 8, 2011, more than 120,000 residents in Pennsylvania and New York were ordered to flee the rising Susquehanna River. Flooding Prompts Evacuations of 100,000 in Pa., N.Y., USA Today, Sept. 8, 2011.
The flooding caused some citizens to examine the NYDEC’s recommendations on fracking, and although the NYDEC proposed banning wells and well pads in 100-year floodplains, it was silent as to whether holding ponds and other infrastructure could be located in floodplains. As one citizen put it, “It is one thing for a truck to spill chemicals into a river. It is another thing for a river to flood hundreds of well sites, collect toxic chemicals, and then spread them across a broader area.”
Others also looked more closely at the floodplain maps and alleged that most appeared to be out of date. In January 2012, the Adirondack Mountain Club submitted comments on the NYDEC’s EIS expressing concern about the NYDEC’s ability to identify where the floodplains are and asked the NYDEC to treat all of New York with the precautions afforded to floodplain areas until the maps are up to date. Neil F. Woodworth, Adirondack Mountain Club Comments on rdSGEIS to Bureau of Oil & Gas Regulation, NYSDEC Division of Mineral Resources, Jan. 10, 2012. The Adirondack Mountain Club also suggested that “[i]n consideration of New York’s recent highly variable weather, there should be no exceptions for allowing open wastewater pits. Even up to date maps cannot ensure that an area will not flood.” Id.
Pennsylvania has experienced overflow from fracking pits, although the overflow does not appear to be related to extreme weather. In December 2009, a wastewater pit overflowed at a gas well in Pennsylvania and an unknown quantity of wastewater entered Dunkle Run, a “high quality watershed.” The company failed to report the spill, and in August 2010 the Pennsylvania Department of Environmental Protection (PADEP) levied a $97,350 fine. PA DEP Fines Atlas Resources for Drilling Wastewater Spill, Water & Wastes Digest, Aug. 2010. In June 2010, one oil and gas company drilling in the Marcellus Shale region of Pennsylvania failed to report a hydraulic oil spill and a wastewater pit liner violation. Chief Oil & Gas Pays $180K Fine for Spilling Oil and Overfilling a Wastewater Pit, Marcellus Drilling News, Jun. 29, 2011. A surprise PADEP inspection found evidence that, among other things, a waste pit was close to overflowing. In this case, the drilling and fracturing had been completed, and the well had been capped months earlier. The operator was charged with violations of the state Oil and Gas Act, the Clean Streams Law, and the Solid Waste Management Act and was assessed a $180,000 fine. Although these incidents do not appear to have involved extreme weather, it is not difficult to imagine the complications that could be magnified by the combination of flowback in wastewater pits and extreme weather conditions.
In the past, federal legislation never regulated hydraulic fracturing because it was always viewed as a state concern. Permits to drill and fracture were issued by individual states, and state environmental agencies oversaw the development and production of natural gas. According to the DOE Report, the “regulation of oil and gas field activities is managed best at the state level where regional and local conditions are understood and where regulations can be tailored to fit the needs of the local environment.” DOE Report, p. 6. Provisions of Two Federal Laws—the Safe Drinking Water Act (SDWA) and the Clean Water Act (CWA)—apply to some drilling activities, specifically those related to wastewater disposal through underground injection or discharge to surface waters. However, the CWA, which generally regulates stormwater discharges from industrial and municipal facilities, specifically exempts uncontaminated stormwater runoff from oil and gas exploration, production, processing, or treatment operations from its National Pollutant Discharge Elimination System permitting program. 33 U.S.C. §§ 1342(1)(2) and 1362(24).
Nonetheless, this federal exemption does not prevent states from requiring erosion, sedimentation, and stormwater controls at well sites. Further, state oil and gas agencies also have jurisdiction over the pits or tanks in which flowback water is typically stored at the surface. EPA is in the early stages of developing Effluent Limitations Guidelines under the CWA for shale gas wastewater treatment, but these guidelines are not anticipated to be released until 2014.
Pennsylvania, where more than 350,000 oil and gas wells have been drilled since the first commercial oil well was developed there in 1859, offers a comprehensive overview of oil and gas regulations. In Pennsylvania, the Department of Environmental Protection’s Office of Oil and Gas Management (OOGM) is responsible for the statewide oil and gas programs. The OOGM oversees the exploration, development, and recovery of Pennsylvania’s oil and gas reservoirs; develops policies and programs for the regulation of oil and gas development and production; oversees the oil and gas permitting and inspection programs; and develops statewide regulations and standards. In particular, the OOGM oversees all hydraulic fracturing operations in the Marcellus Shale region, which underlies about two-thirds of Pennsylvania and portions of New York and West Virginia. As part of the permitting process, a well operator must consider the location of the well and its proximity to surface waters and water supplies. Pennsylvania Department of Environmental Protection, Marcellus Shale: Fact Sheet, Oct. 2011. PADEP’s technical staff then reviews the permit application to determine whether the proposed well would cause adverse environmental impacts. Then, throughout the development and recovery processes, operators must submit reports of well completion, waste management, production, and well plugging. Id.
Natural gas well construction can involve changes to land, including the clearing of land for the building of roads, drilling pads, and pipelines, all of which can speed erosion. Indeed, the drilling pads themselves may be in excess of five acres in the Marcellus region, which can cause increases in stormwater runoff and erosion. In Pennsylvania, gas companies are required to develop an Erosion and Sediment Control Plan that uses preventative measures or Best Management Practices (BMPs) to prevent accelerated erosion and sedimentation. In addition, operators are required to restore and permanently stabilize the site within nine months of completion of well drilling. For drilling activities that disturb more than five acres at one time, the operator must complete and submit an Erosion and Sediment Control General Permit to the PADEP for review and approval.
The PADEP, in cooperation with the Susquehanna and Delaware River Basin Commissions, has developed additional permit guidelines for drilling in the Marcellus Shale formation to create consistent rules for water withdrawal, usage, treatment, and disposal in all areas of the state and to ensure that water quality and use are not threatened by drilling operations. As a result, as part of the permit application process, drilling companies must identify where they plan to obtain and store the water used in their drilling operations and the wastewater produced as a result. If companies plan to use pits or impoundments with an embankment to temporarily store water for drilling activities, then they must meet PADEP standards. Further, pits or impoundments with an embankment for temporarily storing drilling wastes must meet PADEP standards for construction by, for example, having a synthetic liner and may also require a PADEP dam permit.
In February 2012, Pennsylvania passed Act 13, which specifically addresses wells and well-related activities in floodplains. 58 Pa. Cons. Stat., Omnibus Amendments No. 2012-13 (2012). The Act’s provisions, most of which took effect on April 16, 2012, provide for, among other things, substantial revisions to environmental protections for both surface and subsurface activities in floodplains. First, no well site may be prepared or drilled within any floodplain if the well site will have (1) a pit or impoundment containing drilling cuttings, flowback water, produced water or hazardous materials, chemicals, or wastes within the floodplain, or (2) a tank containing hazardous materials, chemicals, condensate, wastes, or flowback or produced water within the floodway. 58 Pa. Const. Stat. § 3215(f)(1)(i) & (ii). Second, a well site is not eligible for a floodplain restriction waiver if the well site will have tank containing flowback or produced water within the flood fringe unless all the tanks have adequate flood proofing in accordance with the National Flood Insurance Program standards and accepted engineering practices. Id. § 3215(f)(2). Third, best practices as determined by the PADEP to ensure the protection of the waters of Pennsylvania must be utilized for the storage and handling of all water, chemicals, fuels, hazardous materials, or solid waste on a well site located in a floodplain. Id. § 3215(f)(4). Finally, the boundary of the floodplain shall be as indicated on maps and flood insurance studies provides by the Federal Emergency Management Agency. Id. § 3215(f)(5).
Act 13 provides a host of additional regulations to prevent potential environmental damage from extreme weather such as flooding. The Act limits the distance that any unconventional well may be drilled within from any existing water well, surface water intake, or other water-supply extraction point to 1,000 feet. Id. § 1325 (a). In addition, sites for unconventional wells may not be developed within 300 feet of streams or springs, although variances are available if protective measures are employed. Id. § 1325(b)(1). Further, well operators are presumed to be responsible for pollution of water supplies within 2,500 feet of the well bore when the pollution occurred within twelve months of the later of completion, drilling, stimulation, or alteration of the well. Id. § 3218(c). The PADEP must consider a broad scope of potential environmental impacts, including the impacts of extreme weather, when reviewing an operator’s proposed water management plan. Id. § 3211(m). Counties or municipalities receiving funds from fees related to unconventional gas wells must use the funds for such purposes as flood plain management. Id. § 2314(g). Similarly, the Marcellus Legacy Fund, which is to be established in the State Treasury, may be used for flood control projects or to acquire land prone to drainage by storms or flooding. Id. § 2315(a)(1).
West Virginia has also recognized that the wastewater disposal is “perhaps the greatest challenge regarding these operations.” State of West Virginia, Department of Environmental Protection, Office of Oil and Gas, Industry Guidance, Gas Well Drilling/Completion, Large Water Volume Fracture Treatments (Draft), Mar. 13, 2009, p. 3. In December 2011, the West Virginia legislature passed, and the governor signed, the Natural Gas Horizontal Well Control Act, a comprehensive statute which requires drillers to provide water management plans, among numerous other provisions intended to protect water supplies, including minimum distances horizontal wells must be from water wells, public water supplies, streams, and wetlands. W. Va. Code §§ 22-6A-1 et seq. Similar to Pennsylvania’s Act 13, West Virginia’s Act requires “casing, sealing or otherwise managing wells” to keep returned fluids from entering ground and surface waters and BMPs to prevent runoff. Id. § 22-6A-8. Further, the Act requires companies to gain approval by the WVDEP for large (210,000 gallons or more) freshwater and wastewater impoundments and provides for regular inspections of impoundments. Id. § 22-6A-9. West Virginia instituted a similar requirement for setbacks from drilling water wells, including that no well may be drilled within 25 feet of a water well or spring and the well pad must be at least 100 feet from a perennial stream, lake, pond, reservoir, or wetland; at least 300 feet from a naturally reproducing trout stream; and at least 1,000 feet from a public water supply intake. Id. § 22-6A-12.
Technology continues to improve, and new ways to handle flowback are already being put into practice. In some cases, “closed-loop” systems are used where the flowback is stored in tanks, providing greater protection from overflows as fluid is circulated directly from the well into steel tanks. N.Y. Draft sGEIS; see also DOE Report. While there is a possibility of corrosion in the tanks, well operators can mitigate this with proper maintenance and inspection.
In addition, operators are using underground injection (UIC). See generally EPA, Basic Information about Injection Wells. This longstanding practice has garnered attention as reports of earthquakes throughout the State of Ohio and elsewhere have been tentatively linked by the U.S. Geological Survey to underground injection wells. See United States Geological Survey, FAQs – Earthquakes Induced by Fluid Injection, 2012. Recent reports, however, have found that the earthquakes possibly triggered by underground injection are so small that the seismic activity is hardly noticeable to the public. A study sponsored by the DOE, conducted by the National Research Council, and released in June 2012 looked at various factors that could connect energy techniques to earthquakes and found that hydraulic fracturing is less likely to cause earthquakes than conventional methods of extracting oil and natural gas. National Resource Council, Induced Seismic Potential in Energy Technologies, June 2012.
In some states, the flowback is hauled offsite to treatment facilities or recycling centers. Notably, most states’ municipal waste and water-treatment facilities are ill-equipped to handle the large volumes of this type of wastewater and are generally not an option for treatment. As a result, EPA is currently working on national pretreatment standards for wastewater heading for municipal sewage-treatment plants or private treatment plants, and some states are considering a ban on publicly owned treatment works accepting wastewater associated with hydraulic fracturing.
Other advances enable the flowback to be treated and reused on site or at other hydraulic fracturing operations. In Pennsylvania, recycling flowback from wells in the Marcellus Shale has become an essential practice since early 2011 when the PADEP requested fifteen public water treatment plants to stop accepting wastewater from wells in the Marcellus. Stephen Rassenfoss, From Flowback to Fracturing: Water Recycling Grows in the Marcellus Shale, JPT, July 2011. Although the PADEP’s order initially was voluntary, EPA followed up with a letter in May 2011 directing the PADEP to make its order mandatory.
Reusing flowback and produced wastewater on-site could reduce both transportation and disposal expenses for operators, but development of on-site treatment systems that can effectively and feasibly treat this waste stream is a work in progress. The PADEP’s order has made the Marcellus region “a proving ground” for the reuse of water flowing back to the surface in the weeks after fracturing, as well as the flow of produced water after that. Id. On-site treatment technologies have already proven capable of returning 70 to 80 percent of the initial water to potable standards, thus making the water immediately available for reuse. Congressional Research Service, Marcellus Shale Gas: Development Potential and Water Management Issues and Laws, p. 19. Technology continues to improve, and recycling is becoming a viable option for the future. Indeed, major Marcellus players such as Range Resources, Anadarko, Chevron, and Chesapeake Energy are moving toward total recycling. Id.
The drilling industry is improving fracturing technology with the goal of completely eliminating the need for water at all in the fracturing process. Hybrid water-frac technologies, which combine the advantages of both conventional gel and water-frac treatments, were developed in the early 2000s to improve stimulation effectiveness while maintaining low costs and lower water use. Jay A. Rushing and Richard B. Sullivan, Improved Water-Frac Increases Production, E&P, Oct. 12, 2007. Hybrid water fracs use less water to generate fracture width and length while keeping net pressures low. Id. For example, inert gases such as nitrogen can be used with a much smaller quantity of water to fracture the rock and transport the propping agents. Id. The result is minimal water needed for the job.
Until water is not needed at all for the fracturing process, proper storage of wastewater and protecting it from extreme weather are going to be concerns. Although hybrid water-frac technologies and recycling may decrease the amount of water used in the fracking process, they will not eliminate the challenges associated with flowback stored in open pits. Cooperation between states and industry in the development and enforcement of appropriate restriction of hydraulic fracturing in floodplains, along with the enforcement of location restrictions for wells, pits, and impoundments, likely presents the best approach to addressing the myriad concerns related to fracking, especially as they relate to environmental protection during extreme weather events. With a cooperative approach and a regulatory framework that is both protective of the environment and supportive of the responsible development of shale gas, extreme weather concerns can be addressed. And as progress is made in the use of closed-loop systems, wastewater treatment, UIC permitting, and implementation of newly imposed location and pit management requirements, many of the questions surrounding fracking and shale gas development can be answered.