Unconventional natural gas development in the Marcellus and Utica shale plays has seen unprecedented growth since 2012. Ohio, Pennsylvania, and West Virginia are now among the top gas-producing states, with Pennsylvania emerging as the second-largest natural gas producer in 2018, behind Texas. U.S. Energy Information Administration, Natural Gas Marketed Production, www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_VGM_mmcf_a.htm (last visited Aug. 8, 2019). The historic rise in production comes with increased volumes of produced water and waste streams that must be managed by natural gas operators. Produced water is naturally occurring brine brought up to the surface from the hydrocarbon reservoir during extraction of natural gas. Although the volume of produced water varies by well and formation, produced water is by far the largest water source by volume generated in the gas production process. U.S. Environmental Protection Agency (EPA), Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action (Apr. 2019), at 3–11, www.epa.gov/sites/production/files/2019-04/documents/management_of_exploration_development_and_production_wastes_4-23-19.pdf. Many unconventional natural gas operators treat, reuse, and recycle produced water to increase their water usage efficiency, cut down on the costs of disposal, and recover valuable materials.
Implementing the most effective strategy for produced water management requires compliance with a complex web of interrelated federal and state laws, which include state oil and gas-related laws, local laws and ordinances, and environmental laws. This article explores the most commonly used management strategies for produced water in the Marcellus and Utica shale plays in these three states and analyzes the federal and state environmental regulatory regimes governing such management alternatives. It begins by examining the chemical characteristics and volume of produced water from an unconventional natural gas well. It then analyzes the federal and state environmental regulatory landscape for the most common ways that produced water is managed: (1) reuse or recycling within or outside the gas field; (2) disposal in underground injection wells; and (3) treatment at commercial treatment facilities, some of which discharge pretreated effluent to publicly owned treatment works (POTWs). While the natural gas industry increasingly searches for ways to harness the full value of produced water, the environmental regulatory landscape for produced water in the Marcellus and Utica shale plays is evolving. It is unclear whether this evolution will keep pace with innovative solutions and technological advances that are being used to maximize produced water’s value.
Volumes and Chemical Composition of Produced Water in Appalachia
Understanding the complexities of produced water management options and their regulatory underpinnings would not be possible without first understanding the volumes and chemical composition of produced water. Since 2009, the volumes of produced water generated have increased considerably. In Pennsylvania alone, produced water volumes from unconventional operations have increased from roughly 10 to more than 50 million barrels per year. Lee Ann L. Hill et al., Temporal and Spatial Trends of Conventional and Unconventional Oil and Gas Waste Management in Pennsylvania, 1991-2017, 674 Sci. of the Total Env’t 623, 626 (2019).
Scientists often refer to produced water as being hypersaline, with some analyses showing total dissolved solids concentrations of more than 200,000 milligrams per liter for a well in the Marcellus Shale play. Hill et al., supra, at 624. These dissolved constituents primarily consist of sodium and calcium, but barium, strontium, and bromide have also been detected in produced water. Id. Naturally occurring radioactive material, particularly radium, can also be found in produced water from unconventional gas wells in the Marcellus and Utica shale plays. Id.
Produced water often shares the chemical characteristics of the brine located in the geologic formation from which natural gas is produced. While many contend that its chemical composition may be influenced by chemical additives used in the hydraulic fracturing process, a recent scientific study suggests that most of the injected water and chemical additives remain within the shale formations and the return flow consists primarily of naturally occurring brines. Andrew J. Kondash et al., Quantity of Flowback and Produced Waters from Unconventional Oil and Gas Exploration, 574 Sci. of the Total Env’t 314, 317 (2017).
Current technologies like crystallization can remove the various dissolved constituents in produced water, and the resulting salts have been sold commercially. Nonetheless, nongovernmental organizations (NGOs) and academics have noted that EPA-approved analytical methods do not exist for many of the known constituents in produced water, prompting concerns that potentially harmful constituents could go unregulated or undetected. U.S. EPA, Study of Oil and Gas Extraction Wastewater Management Under the Clean Water Act, EPA-821-R19-001 (Draft, May 2019) (EPA May 2019), at 26, 28, www.epa.gov/sites/production/files/2019-05/documents/oil-and-gas-study_draft_05-2019.pdf. Furthermore, residuals from produced water treatment may contain radioisotopes for which disposal can be costly. Id. at 20. Operators are forging ahead with creative solutions that maximize the value of produced water, often ahead of agency rulemaking or policy development. See Paul J. Gough, Water a Growing Part of Business for Natural Gas Company, Pittsburgh Business Times, Feb. 15, 2019; Daniel Gleeson, MGX and Eureka JV to Speed Up Petrolithium Recovery Technology Developments, Int’l Mining, June 11, 2019, https://im-mining.com/2019/06/11/mgx-and-eureka-jv-to-speed-up-petrolithium-recovery-technology-developments/.
Produced water management strategies in the Marcellus and Utica shale plays vary based on the location of the well proximity to available treatment and disposal facilities, market forces, and operator preference. For underground injection and reuse or recycling of produced water, the governing environmental regulatory requirements are significantly different depending on the state. EPA is currently evaluating its existing rules concerning the discharge of treated produced water to surface waters and expected to announce any potential changes to the existing federal regulatory requirements in the summer of 2019. Below, we explore the applicable federal and state regulatory requirements for each of the most commonly utilized produced water management strategies and explain why the paradigm for produced water management appears to be trending away from disposal and toward reuse and recycling.
Disposal in Underground Injection Wells
At the beginning of the Appalachian natural gas boom, disposal in underground injection wells was the most common produced water management option. These wells are regulated under the Class II Underground Injection Control (UIC) program established by the Safe Drinking Water Act. 42 U.S.C. § 300h. EPA can delegate the authority to administer the UIC program to states, and Ohio and West Virginia have delegated authority to implement the Class II UIC program for brine or produced water disposal wells. 40 C.F.R. § 147.1800; see 40 C.F.R. § 147.2453. On the other hand, Pennsylvania has opted not to seek delegation to administer the UIC program. Therefore, EPA administers the UIC program, including the issuance of permits for Class II UIC wells, within Pennsylvania. 40 C.F.R. §§ 144.1(e), 147.1951(a).
Pennsylvania’s lack of implementation authority for the Class II UIC program and its relatively unique geology, have resulted in significantly fewer produced water disposal wells as compared to those located in Ohio and West Virginia. Ohio has the greatest number of active produced water disposal wells at 223. Ohio Dep’t of Nat. Resources, Class II Brine Injection Wells of Ohio, http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/Class_II_Map/Class%20II%20Brine%20Injection%20Wells%20of%20Ohio%2007082019.pdf (last visited Aug. 8, 2019), almost four times as many as West Virginia, where there are 59 active Class II disposal wells. Groundwater Protection Council, State of West Virginia Class II UIC Program Peer Review (GWPC WV) (Nov. 2017), at 15. Comparatively, Pennsylvania has roughly ten Class II disposal wells, only one of which is a commercial UIC well. Pa. Dep’t of Envtl. Prot., Underground Injection Control Wells, www.dep.pa.gov/Business/Energy/OilandGasPrograms/OilandGasMgmt/Pages/Underground-Injection-Wells.aspx (last visited Aug. 8, 2019).
The regulatory process for permitting such wells changes drastically from state to state. As noted, EPA administers the Class II UIC well program in Pennsylvania, meaning that it is responsible for drafting permits, completing the public participation process on such permits, and issuing the permits. See 40 C.F.R. Part 124, Subpart A. Challenges to EPA-issued Class II UIC disposal well permits in Pennsylvania are heard by EPA’s Environmental Appeals Board, 40 C.F.R. § 124.19(a), which has, at times, scrutinized EPA regional offices for failing to address fully induced seismicity issues during the permitting process for Class II produced water wells. See, e.g., In re West Bay Exploration Co., 17 E.A.D. 204 (EAB 2016). In addition to an EPA permit, Class II UIC disposal wells in Pennsylvania require a separate permit from the Pennsylvania Department of Environmental Protection. 25 Pa. Code § 91.52. The dual federal-state permitting requirements for Class II disposal wells in Pennsylvania, in addition to obtaining the necessary and sometimes numerous local approvals needed to construct such a well, provide several avenues for third parties to oppose disposal wells.
Similarly, Class II UIC disposal wells in West Virginia require two separate permits, although both are issued by the Office of Oil and Gas in West Virginia’s Department of Environmental Protection (WVDEP). W. Va. Code, Ch. 22; W.Va. Code R. §§ 47-13, 35-4. In addition, WVDEP distinguishes between “commercial” and “noncommercial” UIC disposal wells. A commercial Class II disposal well is any permitted operating facility that accepts fluids produced by another oil or gas operator. WVDEP, Underground Injection Control Class 2 and 3 UIC Wells, Permit Application Package Instructions and Guidance, http://dep.wv.gov/oil-and-gas/GI/Forms/Documents/UIC%20APPLICATION%20PACKAGE%2006-25-2014.pdf. Commercial UIC disposal wells in West Virginia often are subject to additional permitting requirements, such as analytical testing, manifesting requirements, and increased security measures. Id. There are 14 active commercial and 45 active noncommercial UIC disposal wells in West Virginia. GWPC WV, at 15.
Ohio’s Class II UIC disposal program is unique for several reasons. By statute, the Ohio legislature has vested authority for permitting and implementing a specific regulatory program for produced water (i.e., brine) injection wells, known in Ohio as “saltwater injection wells,” in the Ohio Department of Natural Resources (ODNR), the same state agency that also is responsible for issuing permits for unconventional natural gas wells. Ohio Admin. Code § 1501:9-3. Ohio’s regulatory program requires disposal well operators to use state-of-the-art technology. As an example, each produced water disposal well in Ohio must be equipped with an automatic shut-off device that terminates operations if the maximum allowable surface injection pressure on the injection pump is exceeded. Ohio Admin. Code § 1509:9-3-07(G). Similarly, adapting to recent instances where oil and gas-related wells are believed to have caused seismic activity, the ODNR has the authority to require a disposal well operator to conduct a geologic investigation near the injection well, including the completion of seismic surveys. Ohio Admin. Code § 1501:9-3-06(C)(2)-(3). Recent permits issued by ODNR for produced water disposal wells require monitoring for “microseismicity” prior to injection and throughout the well’s operation. Williams Disposal LLC, API Well Number 34-121-2-4636-00-00 (Aug. 8, 2018).
The prevalence of available disposal wells gives natural gas producers in Ohio and the nearby counties of Pennsylvania and West Virginia a cost-effective means of managing produced water and other wastes generated in the natural gas production process. More recently, however, evidence shows that producers increasingly are turning to other management options, at least in Pennsylvania. Hill et al., supra, at 628. Transportation of produced water to disposal wells can drive up costs to the point where this management option is no longer viable. Transportation to UIC wells also comes with risks of spills and accidental discharges, increased traffic, and air emissions. EPA May 2019, at 19. Concerns over induced seismicity caused by underground injection and disposal wells becoming over-pressurized can pose challenges to siting new disposal wells. Id. at 20.
Reuse or Recycling In and Outside the Gas Field
The reported decline in the use and reliance on disposal wells has coincided with repeated and louder calls by natural gas producers, state regulatory agencies, and others to “rebrand” produced water as a valuable resource. Id. at 19. Reusing and recycling produced water in and outside of the gas field can take on many different forms, from simply storing and reusing produced water to stimulate production in another nearby natural gas well to utilizing treatment technology to produce distilled water and other usable products. The environmental regulatory requirements vary, ranging from relatively straightforward for simple storage and reuse to complex and nuanced for advanced treatment and reuse facilities.
Viewed from a federal waste management perspective, Congress temporarily exempted produced water from natural gas wells from the hazardous waste management requirements of the Resource Conservation and Recovery Act (RCRA) in 1980. 42 U.S.C. § 6921(b)(2)(A). At that time, Congress required EPA to conduct a study and publish a regulatory determination on whether produced water and other oil and gas exploration and production-related wastes require regulation under RCRA Subtitle C. EPA published its regulatory determination in 1988, concluding that regulation under RCRA Subtitle C was not warranted because existing federal and state laws were adequate to regulate, among other things, produced water. Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes, 53 Fed. Reg. 25,447 (July 6, 1988). In 2019, following a lawsuit filed by environmental groups, EPA completed a more recent study and arrived at the same conclusion: produced water would remain exempt from RCRA’s nonhazardous waste program. EPA May 2019, at 9-4 to 9-5. Therefore, operators in the Marcellus and Utica shale plays are subject to state solid waste management programs and regulations regarding the management of produced water. These programs differ substantially among the states.
Pennsylvania has perhaps the most comprehensive set of regulations governing storage, treatment, and transportation of produced water. Even when it is being reused or recycled, Pennsylvania treats produced water as a waste under its solid waste program. Consequently, temporary storage or processing of produced water in Pennsylvania requires a solid waste permit and facilities engaging in these activities are considered solid waste transfer facilities. Produced water destined to be used to complete wells is regulated as a residual waste until the moment it is placed down-hole, unless the produced water meets stringent quality standards. The Pennsylvania Department of Environmental Protection (PA DEP) has issued a beneficial reuse general permit for facilities that transfer, process, and use produced water to hydraulically fracture gas wells, known as WMGR123. The current version of the WMGR123 permit expires in October 2020, unless PA DEP renews it.
In addition to undergoing a comprehensive process to obtain coverage under the WMGR123 general permit, operators of produced water management facilities must then comply with the permit’s strict mandates. In addition to requiring compliance with the major Pennsylvania statutes for air pollution, water pollution, and solid waste management, WMGR123 requires operators to comply with (1) various requirements related to storage, including a one-year limitation on storage absent written approval that is based on proportional rates of accumulation and reuse; (2) a prohibition of a point or nonpoint source discharge or runoff from staging, processing, and storage areas to a water of the Commonwealth; (3) a prohibition on mixing beneficially reused produced water with other waste; (4) management requirements for produced water that is not beneficially reused as solid waste, including proper treatment or disposal; (5) a bond requirement to secure the estimated costs of cleanup; and (6) comprehensive cleanup and closure requirements. Recordkeeping requirements, similar to RCRA’s hazardous waste cradle-to-grave requirements, are also required under WMGR123.
WMGR123 also covers scenarios where the produced water facilities are processing or treating the liquid. Produced water ceases its status as a “waste” under WMGR123 when (1) it is transported to a well site, the owner or operator of the well site meets specific requirements, and it is beneficially reused to hydraulically fracture a gas well; or (2) it is treated so that the concentrations of nearly 40 separate parameters are below established levels and stored in an impoundment or other facility designed to hold water. Any facility or operator unable to exempt produced water from classification as a residual waste or unable to meet WMGR123 must apply for and obtain an individual solid waste permit from the PA DEP.
In Ohio, storage, recycling, treatment, and processing of produced water is subject to statutory requirements implemented by the state’s natural resources agency, ODNR. Ohio’s legislature granted ODNR exclusive authority to regulate the storage, recycling, treatment, and processing of brine or produced water. Ohio Rev. Code § 1509.22(C). ODNR has the authority to issue regulations that govern each of these activities, including procedures related to issuing permits. Id. However, to date, ODNR has not promulgated implementing regulations. Instead, it has been authorizing the storage, recycling, treatment, and processing of produced water through administrative orders for “temporary authorization” to manage produced water.
ODNR has issued more than 35 such orders, each of which temporarily authorize some combination of produced water storage, recycling, treatment, or processing. These orders require each facility to operate in accordance with Ohio Revised Code Chapter 1509. ODNR also typically incorporates regulations at Ohio Administrative Code § 1501:9, which contain various requirements for temporary storage of produced water in pits and tanks. Ohio Admin. Code § 1501:9-3-08. The Ohio Supreme Court recently affirmed a judgment in favor of ODNR in an environmental group’s lawsuit seeking to require ODNR to promulgate regulations governing produced water management, effectively allowing ODNR to continue issuing orders temporarily authorizing the storage, recycling, treatment, and processing of produced water for the time being. State ex rel. Food & Water Watch v. Ohio, 153 Ohio St. 3d 1 (Ohio S. Ct. 2018).
West Virginia explicitly allows the use of produced water for hydraulic fracturing. W. Va. Code R. § 35-8:5.6.f. West Virginia allows produced water to be brought to another well location, as long as the produced water is stored “in pits or tanks or centralized pit facilities” at the new location. Id. Centralized pits or impoundments are regulated in West Virginia based on whether they are included within a specific well work permit for an unconventional gas well and their capacity. Off-site centralized pits or impoundments are subject to more stringent requirements. See W. Va. Code R. §§ 35-8-16, 35-8-17. Siting restrictions, synthetic liner requirements, leak detection systems, groundwater and surface water monitoring requirements, and several related operational requirements are required for centralized pits and impoundments. Id.
Temporary storage of produced water in tanks is regulated under West Virginia’s Aboveground Storage Tank (AST) Act, W. Va. Code § 22-30, which was enacted following a 2014 chemical spill into the Elk River. West Virginia promulgated implementing regulations in August 2016. W. Va. Code R. § 47-63. Notably, tanks holding less than 210 barrels of produced water that are not located in a “zone of critical concern” and wastewater process tanks are excluded from the AST Act requirements. Finally, a non-disposal solid waste permit is required to store and treat produced water in West Virginia. W. Va. Code R. § 33-1-3.5a.
Discharge Options for Produced Water
The most controversial produced water management option is the discharge of produced water, treated or otherwise. Any discharge to surface waters would be covered under the Clean Water Act’s National Pollutant Discharge Elimination System (NPDES) permit program. Ohio, Pennsylvania, and West Virginia are each delegated the responsibility to implement the NPDES permit program within their borders. The controversy over discharge options for produced water has centered primarily over two federal effluent limitation guidelines (ELGs) promulgated under the Clean Water Act.
For onshore gas development, EPA prohibited direct discharges of produced water when it revised the ELGs for the Oil and Gas Extraction Wastewater Point Source Category in 2016. 40 C.F.R. Part 435. EPA has imposed a zero-discharge requirement for oil and gas extraction wastewaters, including produced water, from onshore oil and gas activities. 40 C.F.R. § 435.32. When EPA revised these ELGs in 2016, it then prohibited indirect discharges of produced water to POTWs. 40 C.F.R. § 435.33(a)(1). Following a petition for reconsideration filed by the Pennsylvania Grade Crude Oil Coalition in the U.S. Court of Appeals for the Third Circuit in November 2016, EPA extended the deadline of the prohibition until August 29, 2019. Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category––Implementation Date Extension, 81 Fed. Reg. 88,126 (Dec. 7, 2016). On July 5, EPA published notice of its decision to not revise its 2016 rule imposing a zero-discharge requirement for wastewaters from onshore unconventional oil and gas extraction facilities. Decision on Supplemental Information on the Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source Category, 84 Fed. Reg., 32,094 (July 5, 2019).
Although 40 C.F.R. Part 435 prohibits direct discharges of produced water to surface water and indirect discharges to POTWs, the ELGs for Centralized Waste Treatment (CWT) facilities at 40 C.F.R. Part 437 provide an avenue to treat and discharge produced water. The CWT ELGs were last revised in 2003, several years before the proliferation of unconventional natural gas production in the Marcellus and Utica shale plays. However, the unconventional gas industry does not fit well within the current structure of these ELGs. The present subcategories of the CWT ELGs regulate wastewater from metals treatment and recovery, oils treatment and recovery, organics treatment and recovery, and multiple waste streams. 40 C.F.R. §§ 437.10–437.47. Produced water from unconventional natural gas operations does not fit into any of these subcategories as currently defined. That has caused uncertainty and often the excessively stringent application of the ELGs by state agencies as they develop NPDES for CWTs, which in turn has limited the number of CWTs available to accept produced water for treatment. As an example, one state agency has selected the most stringent effluent limits from the various CWT subcategories and included those in a draft NPDES permit. 47 Pa. Bull. 3995 (July 22, 2017) (publishing notice of a draft NPDES permit and the proposed effluent limits for the FRS Kingsley Facility).
Divergent opinions have emerged on whether additional discharge options should be available for produced water. Industry, some state agencies, and some NGOs generally supported increased opportunities for produced water discharge alternatives, while environmental NGOs and academics have raised concerns. In late 2018, EPA began a comprehensive review to evaluate the management of oil and gas onshore facilities and to determine whether there is a need for additional discharge options under the CWA. As discussed above, EPA released a draft Study of Oil and Gas Extraction Wastewater Management under the Clean Water Act on May 15. This study was designed to evaluate “produced water generation, management, and disposal options at regional, state, and local levels for both conventional and unconventional onshore oil and gas extraction.” EPA May 2019, at 1. EPA reviewed various produced water management strategies, assessed various treatment technologies, and solicited input from a variety of stakeholders related to produced water management and whether additional discharge options were warranted under the CWA. The public comment period EPA provided for the study was open through July 1, and EPA encouraged interested parties to provide input on (1) nonregulatory steps EPA could take to encourage the reuse and recycling of produced water, (2) whether it should revise 40 C.F.R. Part 435 to allow for discharge of produced water considering the cost of transporting and treating produced water, and (3) the steps EPA could take to incentivize the reuse of produced water within and outside the gas field. EPA will use the information in the study and comments received to determine the appropriate course of action, with the goal of announcing any next steps later in 2019.
Produced water management will continue to be an issue for natural gas producers as natural gas production in the Marcellus and Utica shale plays continues to increase, especially if the pace of drilling and completing new wells does not keep up with generation of produced water from producing wells. The paradigm for produced water management appears to be shifting from disposal toward a recognition that produced water is a potentially valuable resource. Efforts to make reuse and recycling options more readily available, and even increasing the availability of discharge options, would be welcomed by unconventional natural gas operators and could prove to be environmentally beneficial. Market drivers, however, will only shift the outlook for increased produced water management options so much. Federal and state regulatory regimes must keep pace with the available science and technological advancements.