Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action April 2019 United States Environmental Protection Agency Office of Land and Emergency Management Office of Resource Conservation and Recovery Disclaimer This document has been prepared by the Office of Resource Conservation and Recovery in the U.S. Environmental Protection Agency. Any opinions, findings, conclusions, or recommendations do not change or substitute for any statutory or regulatory provisions. This document does not impose legally binding requirements, nor does it confer legal rights, impose legal obligations, or implement any statutory or regulatory provisions. Mention of trade names or commercial products is not intended to constitute endorsement or recommendation for use. Management of Exploration, Development and Production Wastes Front Matter i Table of Contents List of Tables ................................................................................................................................................ v List of Figures ............................................................................................................................................. vii Definitions ................................................................................................................................................. viii 1. Introduction ........................................................................................................................................ 1-1 Regulatory History.......................................................................................................................................................... 1-1 Changes within the Industry....................................................................................................................................... 1-2 Document Purpose and Scope.................................................................................................................................. 1-4 2. Summary of Agency Actions ............................................................................................................. 2-1 1992 Background for NEPA Reviewers................................................................................................................... 2-1 1992 Review of Operations in Alaskan North Slope ......................................................................................... 2-1 1996-1999 Oil Field Waste Pit Program ................................................................................................................ 2-2 2000 Associated Waste Reports ............................................................................................................................... 2-3 2010 Review of Damage Cases ................................................................................................................................. 2-4 2014 Review of State Regulations ............................................................................................................................ 2-4 2014 Compilation of Best Management Practices ............................................................................................ 2-5 1988-2019 Voluntary Initiatives ................................................................................................................................ 2-5 3. Industry Overview .............................................................................................................................. 3-1 Summary of Site Operations ...................................................................................................................................... 3-1 3.1.1. Well Installation .............................................................................................................................................. 3-1 3.1.2. Well Completion and Production ............................................................................................................ 3-4 3.1.3. Well Maintenance .......................................................................................................................................... 3-6 Oil and Gas Production Rates .................................................................................................................................... 3-6 Waste Generation Rates ............................................................................................................................................. 3-10 Economic Structure ...................................................................................................................................................... 3-11 3.4.1. Revenue ........................................................................................................................................................... 3-12 3.4.2. Employment ................................................................................................................................................... 3-12 3.4.3. Resolution of Available Data ................................................................................................................... 3-13 4. Waste Management ........................................................................................................................... 4-1 Pits ........................................................................................................................................................................................ 4-1 4.1.1. Reserve Pits....................................................................................................................................................... 4-3 4.1.2. Production Pits ................................................................................................................................................ 4-4 4.1.3. Other Pits ........................................................................................................................................................... 4-5 Tanks .................................................................................................................................................................................... 4-5 4.2.1. Closed-Loop Drilling ..................................................................................................................................... 4-6 4.2.2. Production Tanks............................................................................................................................................ 4-6 4.2.3. Modular Large Volume Tanks ................................................................................................................... 4-7 Land Application ............................................................................................................................................................. 4-8 Management of Exploration, Development and Production Wastes Front Matter ii Other Offsite Disposal................................................................................................................................................... 4-9 4.4.1. Landfills .............................................................................................................................................................. 4-9 4.4.2. Other Treatment and Disposal Facilities ............................................................................................. 4-10 Beneficial Use ................................................................................................................................................................. 4-11 5. Waste Characterization ...................................................................................................................... 5-1 Spent Drilling Fluid ......................................................................................................................................................... 5-1 5.1.1. Bulk Concentration ........................................................................................................................................ 5-2 5.1.2. Summary – Spent Drilling Fluids .............................................................................................................. 5-7 Drilling Solids ................................................................................................................................................................... 5-7 5.2.1. Bulk Composition ........................................................................................................................................... 5-8 5.2.2. Leachate ........................................................................................................................................................... 5-16 5.2.3. Volatile Emissions ........................................................................................................................................ 5-17 5.2.4. Summary – Drilling Solids ......................................................................................................................... 5-17 Produced Water ............................................................................................................................................................ 5-17 5.3.1. Bulk Composition ......................................................................................................................................... 5-18 5.3.2. Volatile Emissions ........................................................................................................................................ 5-29 5.3.3. Summary – Produced Water.................................................................................................................... 5-29 Pipe Scale ......................................................................................................................................................................... 5-30 5.4.1. Bulk Content................................................................................................................................................... 5-30 5.4.2. Leachate ........................................................................................................................................................... 5-32 5.4.3. Air Emissions .................................................................................................................................................. 5-33 5.4.4. Summary – Pipe Scale ................................................................................................................................ 5-34 Production Sludge ........................................................................................................................................................ 5-35 5.5.1. Bulk Content................................................................................................................................................... 5-35 5.5.2. Leachate ........................................................................................................................................................... 5-38 5.5.3. Air Emissions .................................................................................................................................................. 5-40 5.5.4. Summary – Production Sludge ............................................................................................................... 5-41 Contaminated Soil and Sediment .......................................................................................................................... 5-41 5.6.1. Bulk Content................................................................................................................................................... 5-42 5.6.2. Leachate ........................................................................................................................................................... 5-44 5.6.3. Air Emissions .................................................................................................................................................. 5-45 5.6.4. Summary – Contaminated Soil and Sediment.................................................................................. 5-45 Conclusions ..................................................................................................................................................................... 5-46 6. State Programs ................................................................................................................................... 6-1 Methodology .................................................................................................................................................................... 6-1 Uncertainties ..................................................................................................................................................................... 6-2 Analysis of Specific Elements Across States ......................................................................................................... 6-4 6.3.1. Waste Management Location Requirements (Siting and Setbacks) .......................................... 6-5 6.3.2. Tank Requirements (Onsite/On-Lease) ................................................................................................. 6-7 Management of Exploration, Development and Production Wastes Front Matter iii 6.3.3. Pit Construction and Operation Requirements .................................................................................. 6-9 6.3.4. Pit Closure Requirements ......................................................................................................................... 6-14 6.3.5. Spill Notification and Corrective Action .............................................................................................. 6-16 6.3.6. Offsite Landfills ............................................................................................................................................. 6-18 6.3.7. Land Application........................................................................................................................................... 6-20 6.3.8. Beneficial Use................................................................................................................................................. 6-22 6.3.9. NORM and TENORM .................................................................................................................................. 6-26 Conclusions ..................................................................................................................................................................... 6-28 7. Review of Existing Evaluations .......................................................................................................... 7-1 U.S. Environmental Protection Agency (1987d) .................................................................................................. 7-1 7.1.1. Evaluation Summary ..................................................................................................................................... 7-1 7.1.2. Uncertainties .................................................................................................................................................... 7-2 7.1.3. Findings .............................................................................................................................................................. 7-6 U.S. Department of Energy (1998) ........................................................................................................................... 7-6 7.2.1. Evaluation Summary ..................................................................................................................................... 7-7 7.2.2. Uncertainties .................................................................................................................................................... 7-7 7.2.3. Updated Analysis............................................................................................................................................ 7-8 7.2.4. Findings ............................................................................................................................................................ 7-12 Conclusions ..................................................................................................................................................................... 7-13 8. Damage Cases ..................................................................................................................................... 8-1 Review of Recent Damage Cases ............................................................................................................................. 8-1 8.1.1. Review Criteria ................................................................................................................................................. 8-2 8.1.2. Findings .............................................................................................................................................................. 8-3 Spill Reporting ................................................................................................................................................................. 8-4 State Inspection and Enforcement ........................................................................................................................... 8-6 Conclusions ....................................................................................................................................................................... 8-9 9. Summary and Conclusions ................................................................................................................. 9-1 10. References ....................................................................................................................................... 10-1 Appendix A: Damage Cases Appendix B: Constituent Database Appendix C: State Programs Management of Exploration, Development and Production Wastes Front Matter iv List of Tables Table 3-1. Estimated Number of Active Wells in 2016 by State ................................................................................... 3-7 Table 3-2. Estimated Crude Oil and Natural Gas Production in 2016 by State. ..................................................... 3-8 Table 3-3. Change in Industry Statistics, 1985 to 2016 .................................................................................................... 3-9 Table 3-4. Estimated E&P Waste Generation in 2016 ..................................................................................................... 3-11 Table 3-5. NAICS 211: Oil and Gas Extraction – Revenues............................................................................................ 3-12 Table 3-6. Oil and Gas Extraction - Employment in 2016 ............................................................................................. 3-13 Table 4-1. Summary of Pit Sizes in Pennsylvania ................................................................................................................ 4-3 Table 4-2. Number of Active Production Pits in California ............................................................................................. 4-4 Table 4-3. Examples of Disposal Pit Sizes in the Permian Basin ................................................................................. 4-11 Table 5-1. Inorganic Elements in Drilling Fluid (mg/L) ..................................................................................................... 5-2 Table 5-2. Organic Compounds in Drilling Fluid (mg/L) .................................................................................................. 5-4 Table 5-3. Radioisotopes in Spent Drilling Fluid (pCi/L) .................................................................................................. 5-5 Table 5-4. Radioisotopes in Residual Solids from Drilling Fluids (pCi/g) .................................................................. 5-5 Table 5-5. Inorganic Elements in Black Shale (mg/kg) ..................................................................................................... 5-9 Table 5-6. Inorganic Elements in Drilling Solids (mg/kg) .............................................................................................. 5-11 Table 5-7. Organic Compounds in Drilling Solids (mg/kg)........................................................................................... 5-13 Table 5-8. Radioisotopes in Stabilized Drilling Solids (pCi/g) ..................................................................................... 5-14 Table 5-9. Constituent Levels in TCLP Leachate from Drilling Solids (mg/L) ......................................................... 5-16 Table 5-10. Inorganic Elements in Produced Water (mg/L) ......................................................................................... 5-20 Table 5-11. Comparison of Measured and Modeled Barium Concentrations (mg/L)........................................ 5-24 Table 5-12. Organic Compounds in Produced Water (mg/L) ...................................................................................... 5-25 Table 5-13. Radioisotopes in Produced Water (pCi/L) ................................................................................................... 5-26 Table 5-14. Comparison of Measured and Modeled Radium-226 Activities (pCi/L) .......................................... 5-29 Table 5-15. Radioisotopes in Scale (pCi/g) ......................................................................................................................... 5-31 Table 5-16. Radon Emanation Fraction from Scale .......................................................................................................... 5-34 Table 5-17. Inorganic Elements in Sludge (mg/kg) ......................................................................................................... 5-36 Table 5-18. Organic Compounds in Sludge (mg/kg) ...................................................................................................... 5-37 Table 5-19. Radioisotopes in Sludge (pCi/g) ...................................................................................................................... 5-38 Table 5-20. Inorganic Elements in TCLP Leachate from Sludge (mg/L) ................................................................... 5-39 Table 5-21. Organic Compounds in TCLP Leachate from Sludge (mg/L) ............................................................... 5-40 Table 5-22. Radon Emanation from Sludge ........................................................................................................................ 5-40 Table 5-23. Barium and Radium in Contaminated Media ............................................................................................. 5-42 Table 5-24. Radon Emanation from Contaminated Media ........................................................................................... 5-45 Table 6-1. Summary of Required Setback Distances in Select States. ....................................................................... 6-6 Table 6-2. Summary of Freeboard Requirements for Pits. ............................................................................................ 6-11 Table 6-3. Summary of Required Fencing and Netting for Pits. ................................................................................. 6-11 Table 6-4. Summary of Required Depth to Groundwater for Pits. ............................................................................ 6-13 Table 6-5. Summary of Pit Closure Requirements. .......................................................................................................... 6-15 Management of Exploration, Development and Production Wastes Front Matter v Table 6-6. Summary of Spill Reporting Requirements in Select States. .................................................................. 6-17 Table 6-7. Summary of Wastes Allowed for Land Application. ................................................................................... 6-20 Table 6-8. Location and Siting Restrictions for Land Application. ............................................................................. 6-21 Table 6-9. Summary of Operational Conditions Required for Land Application. ................................................ 6-22 Table 6-10. Summary of Waste Types Allowed for Beneficial Use. ........................................................................... 6-23 Table 6-11. Summary of Beneficial Use Testing Requirements. ................................................................................. 6-24 Table 6-12. Summary of Restrictions on Placement of Waste Liquids on Roadways. ....................................... 6-25 Table 6-13. Summary of Terminology for Radioactivity ................................................................................................ 6-26 Table 6-14. Ranking of State Oil and Gas Production .................................................................................................... 6-29 Table 6-15. Summary of State Program Regulatory Elements .................................................................................... 6-30 Table 6-16. Most Recent Updates to State Programs .................................................................................................... 6-32 Table 7-1. Comparison of Constituent Data for Produced Water................................................................................ 7-3 Table 7-2. Comparison of Constituent Data for Drilling Fluid ....................................................................................... 7-4 Table 7-3. Comparison of Saturated Zone Partitioning Coefficients (ml/g) ............................................................ 7-6 Table 7-4. Comparison of Inputs for RESRAD Model ....................................................................................................... 7-9 Table 8-1. Summary of Relevant Damage Cases, 2012 – 2018 ..................................................................................... 8-3 Table 8-2. Summary of Reported Spills for Select States, 2014 – 2017 ..................................................................... 8-5 Table 8-3. Summary of State Inspections and Enforcement Actions in 2018 ......................................................... 8-7 Table 8-4. Summary of Inspection and Enforcement Personnel in Selected States, 1987 - 2018 .................. 8-8 Management of Exploration, Development and Production Wastes Front Matter vi List of Figures Figure 1-1: Examples of the Different Types of Oil and Gas Reservoirs and Production Wells. ...................... 1-3 Figure 3-1: Diagram of Standard Well Casing Configurations. ..................................................................................... 3-2 Figure 3-2: Typical Production Operation for Oil, Gas, and Water Separation. ...................................................... 3-5 Figure 3-3: Major Shale Gas and Tight Oil Plays ................................................................................................................. 3-9 Figure 3-4: Comparison of Well Completion and Production Volume, 1997 to 2017. ...................................... 3-10 Figure 4-1: Pits with Visible Liners. ........................................................................................................................................... 4-2 Figure 4-2: Pits with Fencing and Netting. ............................................................................................................................ 4-2 Figure 4-3: Flare Pit. ........................................................................................................................................................................ 4-5 Figure 4-4: Tanks with Secondary Containment. ................................................................................................................ 4-6 Figure 4-5: Modular Large Volume Tanks. ............................................................................................................................ 4-8 Figure 4-6: Land Application of E&P Wastes. ...................................................................................................................... 4-8 Figure 4-7: Treatment and Disposal Facilities. ................................................................................................................... 4-10 Figure 5-1: Relationship Between Barium and TSS in Spent Drilling Fluid ............................................................... 5-3 Figure 5-2: Relationship Between 235U and Excess 226Ra in Residual Solids from Drilling Fluid....................... 5-6 Figure 5-3: Relationship Between 235U and Excess 226Ra in Stabilized Drill Cuttings .......................................... 5-15 Figure 5-4: Oil and Gas Production Zones in the United States (U.S. EPA, 1987d) ............................................. 5-19 Figure 5-5: Relationships of Chloride with Barium and Strontium. ........................................................................... 5-22 Figure 5-6: Relationship of Bicarbonate and Sulfate with Barium and Strontium. .............................................. 5-23 Figure 5-7: Relationship of Chloride and Bromide with Radium-226. ..................................................................... 5-27 Figure 5-8: Relationships of Radium-226 and Radium-228. ........................................................................................ 5-28 Figure 5-9: Relationship Between Barium and Radium in Contaminated Soil ...................................................... 5-43 Figure 5-10: Relationship Between Barium and Radium in Different Deposited Wastes ................................. 5-43 Figure 7-1: RESRAD Model Results With and Without Radon Exposure ................................................................ 7-12 Management of Exploration, Development and Production Wastes Front Matter vii Definitions Definitions of certain terms drawn from the Report to Congress: Management of Wastes from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy (U.S. EPA, 1987a,b,c): Acidize: To treat oil-bearing limestone or other formations, using a chemical reaction with acid, to increase production. Hydrochloric or other acid is injected into the formation under pressure. The acid etches the rock, enlarging the pore spaces and passage through which the reservoir fluids flow. Additive: A substance or compound added in small amounts to a larger volume of another substance to change some characteristic of the latter. In the oil industry, additives are used in lubricating oil, fuel, drilling mud, and cement for cementing casing. Annulus or Annular Space: The space around a pipe in a wellbore, the outer wall of which may be the wall of either the borehole or the casing. Blow Out: To suddenly expel oil-well fluids from the borehole with great velocity. Borehole: The wellbore; the hole made by drilling or boring. Burn Pit: An earthen pit in which waste oil and other materials are burned. Casing: Steel pipe placed in an oil or gas well as drilling progresses to prevent the wall of the well from caving in during drilling and to provide a means of extracting petroleum if the well is productive. Centralized Brine Disposal Pit: An excavated or above-grade earthen impoundment located away from the oil or gas operations from which it receives produced fluids (brine). Centralized pits usually receive fluids from many wells, leases, or fields. Centralized Combined Mud/Brine Disposal Pit: An -excavated or above-grade earthen impoundment located away from the oil or gas operations from which it receives produced fluids (brine) and drilling fluids. Centralized pits usually receive fluids from many wells, leases, or fields. Centralized Mud Disposal Pit: An excavated or above-grade earthen impoundment located away from the drilling operations from which it receives drilling muds. Centralized pits usually receive fluids from many drilling sites. Centralized Treatment Facility (Mud or Brine): Any facility accepting drilling fluids or produced fluids for processing. This definition encompasses municipal treatment plants, private treatment facilities, or publicly owned treatment works for treatment of drilling fluids or produced fluids. These facilities usually accept a spectrum of wastes from a number of oil, gas, or geothermal sites, or in combination with wastes from other sources. Completion Fluid: A special drilling mud used when a well is being completed. It is selected not only for its ability to control formation pressure, but also for its properties that minimize formation damage. Management of Exploration, Development and Production Wastes Front Matter viii Completion Operations: Work performed in an oil or gas well after the well has been drilled to the point at which the production string of casing is to be set. This work includes setting the casing, perforating, artificial stimulation, production testing, and equipping the well for production, all prior to the commencement of the actual production of oil or gas in paying quantities, or in the case of an injection or service well, prior to when the well is plugged and abandoned. Condensate: A light hydrocarbon liquid obtained by condensation of hydrocarbon vapors. It consists of varying proportions of butane, propane, pentane, and heavier fractions, with little or no ethane or methane. Cuttings: The fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Dehydrate: To remove water from a substance. Dehydration of crude oil is normally accomplished by emulsion treating with emulsion breakers. The water vapor in natural gas must be removed to meet pipeline requirements; a typical maximum allowable water vapor content is 7 lb per MMcf. Desander: A centrifugal device used to remove fine particles of sand from drilling fluid to prevent abrasion of the pumps. A desander usually operates on the principle of a fast-moving stream of fluid being put into a whirling motion inside a cone-shaped vessel. Desiccant: A substance able to remove water from another substance with which it is in contact. It may be liquid (as triethylene glycol) or solid (as silica gel). Desilter: A centrifugal device, similar to a desander, used to remove very fine particles, or silt, from drilling fluid to keep the amount of solids in the fluid to the lowest possible level. The lower the solids content of the mud is, the faster the rate of penetration. Drilling Fluid: The circulating fluid (mud) used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation pressure. A water-based drilling fluid is the conventional drilling mud in which water is the continuous phase and the suspended medium for solids, whether or not oil is present. An oil-based drilling fluid has diesel, crude, or some other oil as its continuous phase with water as the dispersed phase. Drilling fluids are circulated down the drill pipe and back up the hole between the drill pipe and the walls of the hole, usually to a surface pit. Drilling fluids are used to lubricate the drill bit, to lift cuttings, to seal off porous zones, and to prevent blowouts. There are two basic drilling media: muds (liquid) and gases. Each medium comprises a number of general types. The type of drilling fluid may be further broken down into numerous specific formulations. Drill Pipe: The heavy seamless tubing used to rotate the bit and circulate the drilling fluid. Joints of pipe 30 ft long are coupled together by means of tool joints. Drill String: The column, or string, of drill pipe, not including the drill collars or kelly. Often, however, the term is loosely applied to include both the drill pipe and drill collars. Enhanced Oil Recovery (EOR): A method or methods applied to depleted reservoirs to make them productive once again. After an oil well has reached depletion, a certain amount of oil remains in the reservoir, which enhanced recovery is targeted to produce. EOR can encompass secondary and tertiary production. Management of Exploration, Development and Production Wastes Front Matter ix Formation: A bed or deposit composed throughout of substantially the same kinds of rock; a lithologic unit. Each different formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation. Formation Water: The water originally in place in a formation. Fracturing: A method of stimulating production by increasing the permeability of the producing formation. Under extremely high hydraulic pressure, a fluid is pumped downward through tubing or drill pipe and forced into the perforations in the casing. The fluid enters the formation and parts or fractures it. Sand grains, aluminum pellets, glass beads, or similar materials are carried in suspension by the fluid into the fractures. These are called propping agents. When the pressure is released at the surface, the fracturing fluid returns to the well, and the fractures partially close on the propping agents, leaving channels through which oil flows to the well. Gas Plant: An installation in which natural gas is processed to prepare it for sale to consumers. A gas plant separates desirable hydrocarbon components from the impurities in natural gas. Gathering Line: A pipeline, usually of small diameter, used in gathering crude oil from the oil field to a point on a main pipeline. Glycol Dehydrator: A processing unit used to remove all or most of the water from gas. Usually a glycol unit includes a tower in which the wet gas is put into contact with glycol to remove the water. and a reboiler, which heats the wet glycol to remove the water from it so the glycol can be recycled. Heater-treater: A vessel that heats an emulsion and removes water and gas from the oil to raise it to a quality acceptable for pipeline transmission. A heater-treater is a combination of a heater, free-water knockout, and oil and gas separator. Hydraulic Fracturing: The forcing into a formation of liquids under high pressure to open passages for oil and gas to flow through and into the wellbore. Hydrocarbons: Organic compounds of hydrogen and carbon, whose densities, boiling points, and freezing points increase as their molecular weights increase. Although composed of only two elements, hydrocarbons exist in a variety of compounds because of the strong affinity of the carbon atom for other atoms and for itself. The smallest molecules of hydrocarbons are gaseous; the largest are solid. Hydrostatic Head: The pressure exerted by a body of water at rest. The hydrostatic head of fresh water is 0.433 psi per foot of height. The hydrostatic heads of other liquids may be determined by comparing their gravities with the gravity of water. Oil and Gas Separator: An item of production equipment used to separate the liquid components of the well stream from the gaseous elements. Separators are vertical or horizontal and are cylindrical or spherical in shape. Separation is accomplished principally by gravity, the heavier liquids falling to the bottom and the gas rising to the top. A float valve or other liquid-level control regulates the level of oil in the bottom of the separator. Management of Exploration, Development and Production Wastes Front Matter x Perforate: To pierce the casing wall and cement to provide holes through which formation fluids may enter or to provide holes in the casing so that materials may be introduced into the annulus between the casing and the wall of the borehole. Perforating is accomplished by lowering into the well a perforating gun, or perforator, that fires electrically detonated bullets or shaped charges from the surface. Permeability: A measure of the ease with which fluids can flow through a porous rock. Pig: A scraping tool that is forced through a pipeline or flow line to clean out accumulations of wax, scale, and so forth, from the inside walls of a pipe. A cleaning pig. travels. with the flow of product in the line, cleaning the walls of the pipe with blades or brushes. A batching pig is a cylinder with neoprene or plastic cups on either end used to separate different products traveling in the same pipeline. Porosity: The quality or state of possessing pores (as a rock formation). The ratio of the volume of interstices of a substance to the volume of its mass. Produced Water: The water (brine) brought up from the hydrocarbon bearing strata during the extraction of oil and gas. It can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process. Propping Agent: A granular substance (as sand grains, walnut shells, or other material) carried in suspension by the fracturing fluid that serves to keep the cracks open when the fracturing fluid is withdrawn after a fracture treatment. Sediment: The matter that settles to the bottom of a liquid; also called tank bottoms, basic sediment, and so forth. Separator: A cylindrical or spherical vessel used to isolate the components in mixed streams of fluids. Shale Shaker: A series of trays with sieves that vibrate to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the sieve is carefully selected to match the size of the solids in the drilling fluid and the anticipated size of cuttings. It is also called a shaker. Stock Tank: A crude oil storage tank. Surfactant: A substance that affects the properties of the surface of a liquid or solid by concentrating on the surface layer. The use of surfactants can ensure that the surface of one substance or object is in thorough contact with the surface of another substance. Tank Battery: A group of production tanks located in the field that store crude oil. Weighting Material: A material with a specific gravity greater than that of cement; used to increase the density of drilling fluids or cement slurries. Wellbore: A borehole; the hole drilled by the bit. A wellbore may have casing in it or may be open (i.e., uncased); or a portion of it may be cased and a portion of it may be open. Well Completion: The activities and methods necessary to prepare a well for the production of oil and gas; the method by which a flow line for hydrocarbons is established between the reservoir and the Management of Exploration, Development and Production Wastes Front Matter xi surface. The method of well completion used by the operator depends on the individual characteristics of the producing formation or formations. These techniques include open-hole completions, conventional perforated completions, sand-exclusion completions, tubing-less completions, multiple completions, and miniaturized completions. Wellhead: The equipment used to maintain surface control of a well including the casinghead, tubing head, and Christmas tree. Well Stimulation: Any of several operations used to increase the production of a well. Workover: One or more of a variety of remedial operations performed on a producing oil well to try to increase production. Examples of workover operations are deepening, plugging back, pulling and resetting the liner, squeeze-cementing, and so on. Workover Fluids: A special drilling mud used to keep a well under control when it is being worked over. A workover fluid is compounded carefully so it will not cause formation damage. Management of Exploration, Development and Production Wastes Front Matter xii 1. Introduction The United States Environmental Protection Agency (“EPA” or “the Agency”) was granted authority to establish a national framework for solid waste management under the Resource Conservation and Recovery Act of 1976 (RCRA; Public Law 94-580). The intent of this law is to conserve energy and natural resources, reduce the amount of waste generated, and ensure that waste is managed in a manner that protects both human health and the environment. Subtitle C of RCRA provides EPA primary authority to promulgate and enforce federal regulations that address management of hazardous wastes from the initial point of generation to the ultimate point of disposal (i.e., “cradle to grave”). Subtitle D of RCRA provides EPA authority to promulgate standards for non-hazardous waste disposal; however, states have the primary authority to implement and enforce these standards. The RCRA statute does not define which wastes are hazardous and what management practices are most appropriate. These determinations are made by EPA based on a review of the potential hazards posed by the individual waste streams. Regulatory History When EPA first proposed regulation under Subtitle C of RCRA in 1978, the Agency deferred the applicability of most of the hazardous waste treatment, storage, and disposal standards for six categories of “special wastes,” which included drilling muds and oil production brines from oil and gas operations. This deferral was intended to last until the Agency could perform further investigation into the composition, characteristics and degree of hazard posed by these large-volume wastes (43 FR 58946). In response to the proposed rulemaking, both Houses of Congress introduced legislation and held hearings and debates to determine whether and how special wastes should be regulated. Because it appeared likely that Congress would act to exempt certain wastes related to utility and energy development, EPA temporarily excluded the special wastes from the final hazardous waste regulations, stating that “this exclusion will be revised, if necessary, to conform to the legislation which is ultimately enacted” (45 FR 33084). On October 21, 1980, Congress amended RCRA with the 1980 Solid Waste Disposal Act Amendments, which included provisions that addressed special wastes (Public Law 96-482). Specifically, Section 3001(b)(2)(A) (“the Bentsen Amendment”) temporarily exempted drilling fluid, produced water and other wastes associated with the exploration, development and production (E&P) of crude oil, natural gas and geothermal energy from regulation under Subtitle C until further study of the associated risks had been completed. This provision required EPA to determine whether regulation under Subtitle C was warranted, submit findings to Congress and publish a final regulatory determination. Furthermore, it stipulated that any future regulation of E&P wastes under Subtitle C would take effect only if authorized by an act of Congress. Management of Exploration, Development and Production Wastes Section 1: Introduction 1-1 The Agency transmitted a Report to Congress entitled Management of Wastes from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy on December 28, 1987 in three volumes that separately covered oil and gas, geothermal, and all associated appendices (U.S. EPA, 1987a,b,c). EPA concluded in this report that stringent regulation from cradle to grave under RCRA Subtitle C was not warranted for these wastes because enforcement of existing state and federal programs would generally be adequate to control the wastes, the large waste volumes generated could severely strain capacity at existing Subtitle C facilities, and the inflexibility of the Subtitle C program would create a great permitting burden on regulatory agencies that could result in undue delays for exploration and production operations. Based on these findings, EPA issued a final determination in 1988 that maintained the exemption from RCRA Subtitle C for E&P wastes associated with primary field operations (53 FR 25447). Exemption from RCRA Subtitle C does not mean that these wastes cannot cause harm to human health or the environment if improperly managed. Rather, EPA concluded that any risks associated with these wastes could be effectively controlled by improvements to existing state and federal regulatory programs. Therefore, the Agency has since pursued a multi-pronged strategy that includes further research, cooperative work with states to review and update programs, federal action outside RCRA Subtitle C, and voluntary programs to reduce waste generation. Changes within the Industry A combination of economic drivers and technological advancements have resulted in changes to the national energy landscape over the past three decades. The two most significant advancements have been the widespread adoption of hydraulic fracturing and directional drilling, which allowed expanded drilling for crude oil and natural gas in black shale and other “unconventional” formations. Hydraulic fracturing is the injection of fluids into the formation at pressures high enough to fracture nearby rock and provide conduits for the oil or gas to flow into the well. Directional drilling is the installation of wells at an angle (deviated or horizontal wells) that allows greater contact between the well and the formation to maximize the fractured area. Although both technologies have existed in some form for years, recent innovations allowed combined application to formations that were previously considered uneconomical to access. Production from unconventional formations represents a growing share of the national output, though a majority is still produced from “conventional” formations located across the country. Figure 1-1 illustrates the different types of wells and hydrocarbon-bearing formations that are currently in production. Management of Exploration, Development and Production Wastes Section 1: Introduction 1-2 Figure 1-1: Examples of the Different Types of Oil and Gas Reservoirs and Production Wells. Conventional hydrocarbon formations are composed of higher-permeability rocks (e.g., sandstone, limestone, dolomite) that initially produce economically-significant volumes of oil or gas without the need for hydraulic fracturing. Hydrocarbons typically do not originate in these formations. Instead, the oil and gas have been driven into these formations from deeper source rocks by a combination of temperature, pressure, and density gradients. Conventional formations are typically located beneath an impermeable (“confining”) layer that limits further migration of the hydrocarbons toward the land surface. Vertical wells are the most common type of well drilled in these formations because the permeable rock allows hydrocarbons to flow toward a centralized well with minimal assistance. As a result, vertical wells represent the vast majority of wells that have been drilled to date and all the wells considered in the 1987 Report to Congress. Unconventional hydrocarbon formations are composed of lower-permeability rocks (e.g., shale, coal beds) that must be hydraulically fractured to produce economically-significant volumes of oil or gas. These formations are often the source rock where the hydrocarbons formed. However, both oil and gas may also become trapped in other low-permeability (“tight”) formations above the source rock. Drilling in unconventional formations typically requires directional drilling to maximize the impact of hydraulic fracturing. As a result, horizontal wells are a growing fraction of new wells drilled in the United States. Management of Exploration, Development and Production Wastes Section 1: Introduction 1-3 Document Purpose and Scope On May 4, 2016, the Environmental Integrity Project, together with six other parties, filed a lawsuit with the United States District Court for the District of Columbia that alleged EPA had failed to perform non-discretionary duties under RCRA, specifically:  Review, and if necessary revise, Subtitle D criteria for oil and gas wastes (40 CFR Part 257).  Review, and if necessary revise, state plan guidelines for oil and gas wastes (40 CFR Part 256). EPA entered into a consent decree on December 28, 2016 that established March 15, 2019 as the deadline for the Agency to either sign a notice of proposed rulemaking under the aforementioned statutes or to sign determinations that revisions are not necessary at this time. The deadline was later extended to April 23, 2019 in response to a temporary lapse in government appropriations that resulted in unavoidable and cascading delays as a result of the Agency shutdown. The purpose of this document is to summarize the information currently available to EPA about the generation, management and ultimate disposition of wastes from E&P operations currently exempt from regulation under RCRA Subtitle C. These wastes are those associated with primary site operations integral to the location of hydrocarbon and geothermal reservoirs, extraction of resources, and removal of impurities necessary to transport the product offsite. This does not include wastes generated as part of offsite transportation, refinement and manufacturing operations. There are a number of wastes that fall under this exemption, but not every type is generated at each drilling site. EPA has taken steps to provide additional clarity on the scope of the E&P exemption through a 1993 Federal Register Notice (58 FR 15284) and an informational booklet (U.S. EPA, 2002). EPA conducted a review of publicly available literature drawn from a wide array of government, industry and academic sources to understand what information has become available since the most recent update to the Agency’s regulatory framework. This review focused on the structure of the industry, the volume and composition of wastes generated, actual waste management practices, applicable state regulations, and documented cases of environmental damage that resulted from any of these practices. The greatest changes within this industry have been in the production of crude oil and natural gas. Available data indicate that geothermal energy remains limited to a few states and has not undergone a similar surge in production. Accordingly, the majority of new information identified in the literature is focused on production of crude oil and natural gas. Therefore, the discussion in this document also focuses primarily on these associated wastes. The information gathered for this document will be used to determine whether a reasonable probability of adverse effects to human health or the environment exists from the management of E&P wastes. Based on this review, EPA will identify any further steps necessary to prevent or substantially mitigate potential sources of harm, which may include updates to regulations or other practical and prudent non-regulatory actions. Management of Exploration, Development and Production Wastes Section 1: Introduction 1-4 2. Summary of Agency Actions To help fulfill the obligations enumerated in the consent decree, EPA first reviewed existing sources of information relevant to the current state of E&P waste management and then conducted an extensive literature review to identify information that had since become available. This section details the actions previously undertaken by EPA in support of RCRA to improve existing regulatory programs and enhance understanding of both the industry and the associated wastes. EPA has also taken a number of additional actions related to E&P wastes under other Agency programs, these actions are outside the scope of this review.1 Subsequent sections of this document discuss information that was assembled through the literature review, organized around specific factors that EPA considered relevant in its review. 1992 Background for NEPA Reviewers Pursuant to the National Environmental Policy Act (NEPA) and Section 309 of the Clean Air Act, EPA reviews and comments on major federal actions that may significantly affect environmental quality. EPA developed a background document on E&P site operations to assist EPA staff with development of comments on NEPA documents for the exploration and production of oil and gas on federal lands (U.S. EPA, 1992a). EPA recognized that this document may also be useful to operators that plan work on federal lands and federal land managers that prepare Environmental Impact Statements. This document provides general descriptions of site operations, environmental impacts that may be associated with each operation, possible prevention/mitigation measures, and types of questions that should be raised as part of the Agency’s review. It is not intended to be exhaustive and does not include discussion on impacts to floodplains, archaeological resources, and other traditional NEPA concerns that can be present at any type of development. Rather, it focuses on operations specific to oil and gas with the greatest potential to impact the environment, which include well site and road construction, drilling fluid and cuttings management, produced water disposal, product gathering systems (pipelines and storage tanks), and production operations. The document outlines general concerns about impacts to groundwater, surface water, air, ecosystems and sensitive receptors, though it acknowledges that every operation is unique and additional analyses could be necessary to fully understand the risks posed by a specific project. 1992 Review of Operations in Alaskan North Slope EPA led a study to evaluate the objectives, implementation and enforcement of the state regulatory program for E&P wastes on the North Slope of Alaska. This study included information from site visits to the North Slope by personnel under contract to EPA in 1988; a review of state implementation and enforcement actions; available information on facility history and waste management practices; and 1) A summary of the different actions taken across the Agency to better understand and address potential environmental impacts from E&P operations is available online at: https://www.epa.gov/uog. Management of Exploration, Development and Production Wastes Section 2: Summary of Agency Actions 2-1 comments received on a 1989 draft report from the Alaska Department of Environmental Conservation (AKDEC), the oil and gas industry, environmental groups, and other interested parties. The Agency completed a report documenting the results of the case study in 1992 (U.S. EPA, 1992b). EPA found evidence of improved waste management practices on the North Slope and significant increased attention to environmental issues. However, EPA also observed significant tracts of dead vegetation during site visits surrounding various service company sites. Service companies perform a variety of operations on the North Slope, including supplying oil field chemicals, vehicle maintenance, fuel service and drum disposal. EPA also observed impacted vegetation adjacent to a number of well pads that appeared to be the result of various spills. EPA documented ongoing activities believed to be associated with observed damages, such as releases through reserve pit berms and dikes, mishandling of oily wastes, and poor housekeeping practices with regard to handling of chemicals and equipment. To address the issues identified during this study, EPA made a series of recommendations. First, to dedicate additional resources for training, compliance monitoring and enforcement to improve compliance on the North Slope. Second, to strengthen enforcement of existing regulations, with a focus on service company operations. Finally, to improve coordination among state agencies to save resources by eliminating duplication of effort and simplifying compliance and enforcement activities. EPA also recognized that the state had already taken positive steps to improve the regulatory program for these wastes. The program had recently been updated, which may not have been fully captured in the Agency’s report, and additional reviews had been scheduled. In addition, AKDEC had plans for additional staff positions, though that had not occurred at the time of this report. 1996-1999 Oil Field Waste Pit Program EPA Region 8 and the U.S. Department of Interior (U.S. DOI) Fish and Wildlife Service (FWS) Region 6 created a team to assess the management of E&P wastes. Co-regulators participating in the effort included state regulatory agencies, tribal agencies, and the U.S. DOI Bureau of Land Management and Bureau Indian Affairs. The primary objectives of this effort were to determine where oily waste in open pits posed a significant threat to migratory birds or other wildlife and to assess the potential threat posed by these facilities to surface water and groundwater resources. EPA compiled the results of this effort and provided recommendations to strengthen the effectiveness of state regulatory programs (U.S. EPA, 2003). Between 1996 and 1999, sites were assessed in all six states in EPA Region 8 (i.e., Wyoming, Montana, Colorado, North Dakota, South Dakota, Utah). Initial assessments were conducted by visual inspection during flyovers. The criterion for identifying potential problem sites was exposed oil, either on the ground or on the surface of a pit. However, other observed conditions (e.g., discharges to surface water, abandoned drums) that may pose a risk to human health or the environment were also identified as warranting further investigation. In less than four years, 15% to 20% of the approximately 28,000 pits (based on information provided by co-regulators) in EPA Region 8 were observed during aerial surveys. Many of these sites were found to be well-managed. Most pits (between 80% and 90%) did not present Management of Exploration, Development and Production Wastes Section 2: Summary of Agency Actions 2-2 an apparent threat to the environment and were not flagged for further attention. 516 sites, some with multiple pits, were identified as warranting ground inspection and 475 were ultimately visited. When apparent problems were identified from the aerial assessments, the information was shared with co-regulators who in turn distributed it to the regulated community. Owners and operators of potential problem sites were informed that their sites would be inspected no less than thirty days after the initial contact giving the operators an opportunity to address existing problems. As a result, a large percentage of flagged sites had addressed the problems prior to ground inspections. Problems that persisted at the time of the ground inspection were subsequently resolved through either compliance assistance or enforcement actions (e.g., RCRA Section 7003). In total, 348 informal actions (e.g., notice of violation) and 80 formal enforcement actions were taken. Of the facilities visited, 61% of production facilities and 100% of centralized disposal facilities required some sort of follow-up to correct environmental conditions or non-compliance. EPA made a series of recommendations to address the waste management issues identified during this effort. First, to improve communication channels and relationships among co-regulators and Agency programs by sharing information and improving the collective understanding of the various state and federal regulatory requirements. Second, to continue improvements to regulatory programs by incorporating minimum standards compiled by EPA, the Interstate Oil and Gas Compact Commission (IOGCC), the American Petroleum Institute (API) and other organizations. Finally, to strengthen compliance monitoring and enforcement, with a particular focus on commercial disposal facilities. 2000 Associated Waste Reports Data collection in support of the 1987 Report to Congress focused primarily on produced water and spent drilling fluid which accounted for over 98% of total volume of E&P wastes generated. Many of the remaining lower-volume wastes were co-managed in the same management units and so were anticipated to have a minimal impact on the composition of the commingled waste. However, EPA continued to compile and analyze available information on other E&P wastes from contacts within other federal agencies, literature reviews, and industry databases to address data gaps that remained for these lower-volume wastes. In 1992, EPA collected and analyzed samples of wastewater and solid waste from various E&P operations. These and other available data were discussed in three separate reports, collectively known as the Associated Waste Reports:  Tank Bottoms and Oily Debris (U.S. EPA, 2000a)  Dehydration and Sweetening Wastes (U.S. EPA, 2000b)  Completion and Workover Fluids (U.S. EPA, 2000c) These reports summarize information on how the wastes are generated, waste volume and composition, management practices, and damages that could result from mismanagement. Available information showed enormous variability in the volume, composition and management of each waste. Yet the small number of samples relative to the volume and diversity of these waste streams, as well as analytical issues, such as matrix interference, introduced uncertainty into the data. EPA was unable to determine Management of Exploration, Development and Production Wastes Section 2: Summary of Agency Actions 2-3 whether the data provided a reasonable distribution of waste concentrations or what factors contributed most to high waste concentrations. These uncertainties prevented the Agency from drawing broad conclusions about the wastes. However, EPA was able to provide recommendations for waste minimization and pollution prevention techniques that could be adopted by the industry to reduce the quantity of waste generated. 2010 Review of Damage Cases The Natural Resources Defense Council (NRDC) submitted a petition to EPA on September 8, 2010 requesting that E&P wastes be regulated as hazardous under Subtitle C of RCRA. The petition argued that “the toxicity of exploration, development and production wastes, their release into the environment, threats to human health, the increasing amount of these types of wastes being generated, the inadequacy of existing state regulations, enforcement and oversight, and the feasibility and economic benefits of using disposal techniques that are less harmful to the environment all support regulation under Subtitle C.” In support of the petition, NRDC provided information on alleged release incidents of E&P waste. A list of the citations contained in the petition is provided in Appendix A: (Damage Cases). In response, EPA examined the documents listed in the petition, as well as the additional sources referenced in those documents, to better understand the nature and frequency of incidents alleged to have caused harm to human health or the environment. EPA identified 260 separate incidents from the sources provided that involved management of E&P wastes in 18 states between 1980 to 2010. Of these, a total of 176 involved management in pits, 12 involved some form of land application (e.g., land farming), 68 involved other miscellaneous releases (e.g., air emissions, spills), and the remaining four had insufficient information available to reliably evaluate. The sources also had information on 1,936 reports of citizen complaints, spills and other releases in three states. EPA examined these additional incidents, but found that many were occurred some time ago and it was not possible to determine the cause or nature of the incident or the alleged damage. Therefore, EPA excluded these additional reports from the review. The vast majority of incidents reviewed were the result of non-compliance with current state regulations. All but two the 176 incidents related to management in pits and one of the 12 incidents related to land application could be attributed to violations of state regulations. This indicated that improved enforcement of existing regulations could have prevented most of the identified incidents. Based on the review of data provided by NRDC, it remained unclear that imposition of new federal regulations would substantially reduce issues of non-compliance. Rather it suggested that increased inspections and tighter enforcement of existing state regulations would reduce the frequency of violations. 2014 Review of State Regulations Many states developed and updated legislation and regulations in response to the increased use of hydraulic fracturing at E&P sites. EPA undertook a review of state regulations to better understand exactly how state regulations had changed since the 1988 Regulatory Determination and any gaps in Management of Exploration, Development and Production Wastes Section 2: Summary of Agency Actions 2-4 coverage that may exist (U.S. EPA, 2014a). This review included a direct reading of published state regulations and statutes for pits and tanks, as well as reports and databases compiled by State Review of Oil and Natural Gas Environmental Regulations (STRONGER) and the U.S. Department of Energy (DOE). In total, EPA reviewed regulations from 26 of the 33 states that account for nearly all natural gas production in the United States. To ensure that the Agency’s understanding and representation of the state regulations were accurate, EPA followed up with staff from each state agency. This review did not aim to rank or otherwise evaluate the quality of individual state programs. Instead, it identified trends and common elements among the states. EPA found that state regulations for pits and tanks commonly included requirements for liners, secondary containment, minimum setback distances, minimum freeboard, inspection, maintenance, closure and reclamation. In contrast, states often did not have requirements for groundwater monitoring, leachate collection, air monitoring or waste characterization. The absence of these particular requirements is notable because it is a divergence from typical state programs for other wastes (e.g., municipal solid waste), though it is known that additional requirements are often included in the facility permits to allow consideration of differences in local geology, land use, water resources and other factors. However, EPA was not able to conduct a similarly thorough review of individual permits as part of the analysis. 2014 Compilation of Best Management Practices The Agency conducted a literature review to develop a list of publicly available sources of best management practices (BMP, also known as “voluntary management practices”) for E&P wastes in pits, tanks, and land application/disposal units (U.S. EPA, 2014b). The purpose of this effort was to expand awareness and encourage the continued improvement of existing BMPs. EPA reviewed a total of 85 publicly available documents and databases developed by industry, state and federal agencies, and nongovernmental organizations that range from international to regional in scope. From this list of sources, EPA selected 14 examples of BMPs for more in-depth summary. It is important to note that this study did not aim to evaluate or advocate for any specific practice, rather it was an attempt to provide information on specific practices in common use throughout the industry. Based on the review of existing documents, EPA concluded that there is a great deal of existing guidance on BMPs that is readily available to the public. Many of these sources include recommended technical criteria for pits and tanks that cover one or more of the following areas: permitting, construction, operations (e.g., maintenance, inspection, monitoring, testing, remediation), and closure. These criteria are designed to be flexible and allow practices to be matched and adapted to the needs of the specific project and local environment. There are also ongoing efforts by various stakeholder groups to continuously refine and expand upon existing guidance. 1988-2019 Voluntary Initiatives The Interstate Oil and Gas Compact Commission (IOGCC) was chartered by Congress in 1935 and represents the governors from 30 oil and gas producing states. In 1988, IOGCC proposed a peer review for state regulatory programs for E&P wastes. EPA provided grant funding to the IOGCC to develop Management of Exploration, Development and Production Wastes Section 2: Summary of Agency Actions 2-5 and administer these reviews. The Agency also provided grant funding to citizen groups to encourage their participation in the state reviews. From 1990 through 1997, the IOGCC administered voluntary reviews of 17 individual state regulatory programs for the oil and gas industry through a multistakeholder process. When deficiencies were identified, the IOGCC team provided recommendations for improvements. However, in 1997, this review process was discontinued. EPA continued to work with the stakeholders to revive the review process and, in 1999, STRONGER was established as an independent, non-profit educational organization to continue the administration of state reviews. The multi-stakeholder board of directors includes equal representation from the oil and gas industry, state and federal regulatory agencies, and environmental public advocacy groups. EPA provided grant funding and participated on all reviews as an official observer. All reviews are open to the general public. Altogether, this provides a series of checks and balances to the review process that ensures the finalized recommendations are appropriate and impartial. The original guidelines used in the review of state programs were completed in 1990 based on minimum acceptable standards developed for six topic areas by subcommittees and a survey of existing regulatory programs in oil and gas producing states.2 These guidelines have been updated multiple times since then to reflect emerging issues such as abandoned wells, radioactivity, hydraulic fracturing and recycled fluids. The updates also incorporated EPA guidance developed since 1990. Draft guidelines are distributed to states, environmental groups, industry associations, and posted on the STRONGER website for public comments. The comments received are incorporated and a final draft is prepared for board approval. The most recent update to the guidelines were adopted in 2017 (STRONGER, 2017). These guidelines extend beyond the scope of RCRA and include recommendations for other topics such as well construction, data management, and fee calculation. To date, 22 state programs have been reviewed by IOGCC or STRONGER at least once. These states collectively account for over 94% of onshore oil and gas production in the United States. A total of 45 separate reviews have been conducted among these states that include 22 initial reviews, 15 follow-up reviews, and 8 single-topic reviews (i.e., hydraulic fracturing, air quality).3 As of 2009, STRONGER estimated that over 75% of the recommendations (306 of 405) had been adequately incorporated into state programs (STRONGER, 2016). These recommendations have led to documented changes to state programs for pits, tanks, offsite disposal, centralized facilities, spill reporting, corrective action, remedial standards, and other areas. In addition, some states have taken steps to further characterize wastes, share information with the public, and increase staffing to support enforcement. In addition to IOGCC and STRONGER, EPA has also funded initiatives for individual states. These include grants to Alaska to identify and promote pollution prevention opportunities for the oilfield service industry (AKDEC, 1994) and to Texas to develop a waste minimization and outreach program for operators in Texas (TXRRC, 2001). EPA continues to support efforts to reduce the amount of waste 2) The six initial topic areas included: pits, land application, commercial facilities, state and federal relations, personnel and resources, organization and coordination, and statutory authority. 3) Reports for all STRONGER reviews are made available online at: http://www.strongerinc.org/state-reviews. Management of Exploration, Development and Production Wastes Section 2: Summary of Agency Actions 2-6 generated and ensure that waste is managed in a manner that protects both human health and the environment. Management of Exploration, Development and Production Wastes Section 2: Summary of Agency Actions 2-7 3. Industry Overview The oil and gas industry is expansive and encompasses the exploration, extraction, refining, transport and marketing of oil and gas as a fuel source and feedstock for a range of commercial products. This document focuses on the upstream sector of the industry that engages in E&P for crude oil and natural gas from subsurface formations. This section summarizes the available information on the structure of this industrial sector, the operations performed in the course of normal business operations, and the types and quantities of waste that may be generated in the process. Summary of Site Operations The first step in E&P operations is a pre-siting assessment of local geology to determine the potential for oil and gas production. Areas that might contain oil or gas reserves are first identified using field surveys and seismic data before obtaining the mineral interests on the property from the landowner and approval to drill from the relevant state agencies. Exploratory wells may initially be installed onsite to gather more detailed geological data on rock and fluid properties, initial reservoir pressure, and reservoir productivity. If exploratory wells identify a formation that can produce salable quantities of crude oil or natural gas, then the development wells may be installed to extract the hydrocarbons. Well exploration, development and production involves a wide array of operations to install the well, extract the hydrocarbons, remove of impurities from the crude oil and natural gas prior to distribution, and maintain the long-term integrity of the well. The following text provides a general summary of common operations that may be performed during the installation and productive life of a well, as well as the wastes that may be generated. This discussion is not intended to provide an exhaustive list of operations or waste types; this document groups wastes into broader waste streams based on similar composition and management practices. 3.1.1. Well Installation A drilling pad is first prepared to support a drilling rig and any ancillary equipment, such as trucks associated with the operation and trailers to house personnel and equipment. The size of a pad typically ranges between one-half and one acre, depending on the nature of the operation and the number of wells that will be drilled. The lease or property boundaries and well location are staked out and the site is excavated to clear the area of trees and other vegetation. Then an access road (“lease road”) is built and any pits and tanks needed to manage waste are installed. Modern oil and gas wells are typically drilled with rotary drill rigs. These rigs rotate the drill pipe with an attached drill bit (“drill string”) to create the borehole (“wellbore”). As drilling progresses, additional drill pipe segments are added in successive sections (“joints”). The threads on each joint are coated with a compound that protects the threads and prevents seizing when the joints are connected together. At predetermined intervals, drilling is halted and the drill string is removed from the wellbore to install a steel casing. The purpose of this casing is to prevent collapse of the surrounding rock into the wellbore, isolate high-pressure formations, prevent intrusion of formation fluids into the wellbore during Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-1 construction, and avoid mixing of hydrocarbons and other contaminants with overlying aquifers during production. The first interval of casing (“conductor casing”) extends a relatively short depth, typically between fifty and several hundred feet, to prevent collapse of the initial wellbore and to provide support for deeper casing strings. After each interval is installed, cement may be pumped down the casing to seal the annular space. When drilling resumes, the drill bit is advanced to a point just below where the next casing string or surface casing will extend. The second interval of casing (“surface casing”) is smaller in diameter and typically extends anywhere from 50 to 100 feet below the lowermost aquifer of potential use, as specified by state requirements. Subsequent intervals of casing (“intermediate casing”) are installed as needed to reach the target formation and isolate unstable formations that may collapse or cause loss of fluid circulation. If this interval is located in a stable (“competent”) formation, the operator might choose not to install intermediate casing and produce through an open hole. The final interval of casing (“production casing”) typically runs the full depth of the well and isolates the production zone from other formations. Figure 3-1 provides an example of standard well casing configurations. Figure 3-1: Diagram of Standard Well Casing Configurations. Wells may be advanced directly beneath the well pad (“vertical well”) or at an angle that can extend some distance beyond the footprint of the well pad (“deviated well”). The initial portion of a deviated well is typically vertical and drilled the same as any other vertical well. At the point the well begins to deviate (“kickoff point”), the curved section of the well is drilled using a hydraulic motor mounted directly above the bit and powered by the drilling fluid. This allows the drill bit to be rotated by the hydraulic motor without also rotating the drill pipe. Various sensors in the drill string provide information about the location and speed of the bit and the temperature and pressure of the formation, which allows precise control over the movements of the drill string. Deviated wells may be installed at a range of different angles, though wells in unconventional formations are often installed fully parallel with the hydrocarbon formation (“horizontal well”) to allow greater contact between the well and the formation for hydraulic fracturing. Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-2 During well installation, an engineered fluid is circulated down the drill pipe and out of nozzles in the drill bit (“drilling fluid” or “drilling mud”). This fluid is used to cool and lubricate the drill bit, control pressure within the borehole, seal drilled formations to prevent fluid loss, and to transport drill cuttings to the surface. The type of drilling fluid used depends on the characteristics of the formations that will be drilled:  Gas-based fluids (GBFs) can be entirely gas (carbon dioxide, nitrogen) or may be gas entrained in water with foaming agents (e.g., surfactants). GBFs are used to drill wells under low-pressure and low-temperature conditions in relatively shallow wells and formations like limestone and coalbeds.  Water-based fluids (WBFs) typically consist of 80% water and 20% clay and other additives. The water can be either fresh or salt water. WBFs are used to drill deeper wells under moderate-to-high pressures and low-to-moderate temperatures.  Oil-based fluids (OBFs) typically consist of around 55% petroleum distillate, 30% water, and 15% clay and other additives. OBFs are used to drill wells under extreme temperatures and pressures where water could evaporate or freeze (e.g., Arctic drilling) or where reactive formations could be encountered (e.g., hydratable shale, salt domes).  Synthetic-based fluids (SBFs) are formulated similar to OBFs. SBFs are oil-like fluids formulated from vegetable esters derived by reacting an acid with an alcohol, olefins or alkenes (e.g., ethene), synthetic paraffins (paraffin-like material produced from natural gas), and alkyl benzenes (single ring aromatic hydrocarbons). SBFs are formulated to biodegrade more quickly in the environment and have lower bioaccumulation potential. These synthetic fluids tend to be more expensive and so are primarily used when drilling in environmentally sensitive areas, such as offshore and coastal areas, that require performance equivalent to an OBF. Drilling fluid may simply be foam, fresh water or salt water at the start of drilling. However, as drilling progresses and formation pressures and temperatures increase, new fluids may be introduced that contain additives to increase the weight and enhance the performance of the fluid. Weighting agents are commonly added to increase the specific gravity (weight) of the fluid. Barium sulfate is often used as the weighting agent in WBFs, OBFs and SBFs but hematite (iron oxide) may also be used, particularly in OBFs. Another common additive is clay (typically bentonite) to further increase the specific gravity of the fluid and to help protect and seal wellbore formations. Drilling fluids return to the ground surface through the annular space between the drill pipe and the wellbore. The used fluids are mixed with the fragments of soil, rock and other pulverized material that are dislodged by the drill bit (“drill cuttings”). Cuttings are mechanically separated from the drilling fluids to the extent practicable with equipment such as filter belts or centrifuges and sent to a reserve pit or tank. Recovered drilling fluids are treated and reused until the fluids become too contaminated to recycle, the geological conditions in the wellbore require new fluid formulation, or drilling has been completed. At that point, the spent drilling fluid is also sent to the reserve pit or tank. Drill cuttings and spent drilling fluid are the wastes generated in greatest volumes during well installation. A number of other wastes may be generated in smaller volumes that include spent spotting fluid, water used to Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-3 wash the drill rig, and spills of various materials around the drill rig (e.g., cement) may be generated in smaller volumes over the course of drilling. These wastes are typically managed together with the drill cuttings and drilling fluid in onsite reserve pits or tanks prior to disposal. 3.1.2. Well Completion and Production Once the well has been installed, any drilling fluid remaining in the well is replaced with a dense fluid free of any solids that could react with the formation water or otherwise plug the production zone. This fluid is often a heavy brine made with dissolved inorganics salts (e.g., chloride, bromide) that is used to control the pressure down-hole and to prevent formation fluids from entering the well while the well is completed. Once the completion fluid is in place, a perforating gun loaded with shaped charges is lowered into the production zone and remotely fired. The charges pierce the casing and cement, creating holes that will allow oil and gas to flow into the wellbore once the completion fluid is removed. Well stimulation techniques may be used after well completion to widen and connect conduits in the formation and allow the oil and gas to flow more freely into the well. Acid may be injected at lower pressures and allowed to remain within the well for some time to dissolve any limestone, dolomite or calcite minerals present within the reservoir rock. Other fluids may be injected at higher pressure to create new fractures within the rock, also known as hydraulic fracturing. Common base fluids for fracturing are water or an energized mixture of water and entrained gas (e.g., nitrogen, carbon dioxide). Less common base fluids may be a mixture of water and petroleum distillate or entirely hydrocarbons and alcohols. In specific cases, acids may be used as the primary fracturing fluid to dissolve carbonate reservoirs. After the initial fracturing, gelling agents are added to increase the viscosity of the fluid and to facilitate transport of a proppant into the fractures so that the pressure in the formation does not reseal the fractures. Common proppants include various sizes of sand, ceramic beads and sintered bauxite. Next, a gel breaker is injected into the well to reduce the viscosity of the fracturing fluid and allow it to return to the surface without the proppant. These fluids may also contain a number of other additives intended to protect the integrity of the well and the formation during injection, such as friction reducers, scale and corrosion inhibitors, biocides and others. Further discussion of these other additives can be found in the Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0 (U.S. EPA, 2015a). The fluids produced from a well are typically some mixture of crude oil, natural gas and associated water. This mixture is immediately directed to one or more oil and gas separators that use baffles or other means to partition the different phases based on density. Natural gas rises to the top of the tank. Depending on the volume of gas generated and the available infrastructure, the natural gas may be flared off or collected for sale. Natural gas may require additional treatment to remove impurities prior to sale. Common treatments include passing the gas through specialized filters to remove either water vapor (“dehydration”) or acidic gases, such as hydrogen sulfide and carbon dioxide (“sweetening”). These treatments may produce other salable products, such as elemental sulfur, compressed carbon dioxide, and natural gas liquids (e.g., propane, butane). The remaining natural gas, which is primarily Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-4 methane, is sent to a transmission line for transport for sale.4 The separated crude oil is skimmed off the top of the water and sent to a heater treater that accelerates the breakdown of any emulsified water by applying heat. The remaining crude oil is sent to tanks for storage until it can be transported offsite for sale or further refinement. Figure 3-2 provides an example of typical operations to separate out oil and gas for transport. Figure 3-2: Typical Production Operation for Oil, Gas, and Water Separation. The waste generated in the greatest volume during production by far is the wastewater that flows from the well. At first, the wastewater might be composed primarily of hydraulic fracturing fluids that have returned to the surface (“flowback”), but over time the injected fluids will mix with the water in the hydrocarbon-bearing formation (“formation water”). This mixing makes it difficult to determine what fraction of the wastewater originates from the formation at any given time. Therefore, the waste liquids generated from a well are collectively referred to as “produced water.” At the ground surface, produced water is separated from any salable hydrocarbons and sent to pits or tanks for storage prior to disposal or recycling back into fracturing fluids. Another waste routinely generated during production consists of solids that settle out and accumulate in flowlines, pits, tanks and other equipment along the production line. These solids are commonly referred to as sediment, sludge or vessel bottoms. Depending on where in the production line the sediment accumulates, it may contain a variable mixture of proppant, formation solids, chemical precipitate, paraffins, condensed liquids, heavy hydrocarbons and other substances that settle out of solution. These solids must be cleaned out of the pits and tanks periodically and are expected to be managed as a separate waste stream. Cleaning may be done manually or with the aid of mechanical 4) Because natural gas often requires processing to remove water vapor and other impurities prior to entering the sales line, gas plants are considered to be part of primary operations regardless of the location with respect to the wellhead. Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-5 devices (“pigs”) used to scrape the insides of narrow pipes and flowlines. If the solids contain high levels of oily residue, the solids may be sent to a crude oil reclamation facility to salvage the oil. Occasionally, if the solids have a high fluid content, they may be disposed along with the produced water. Otherwise, the solids are likely to be sent as a separate waste stream for disposal. A number of additional waste streams may be generated periodically during oil and gas production at far smaller volumes than produced water. Examples include filter socks used to remove solids from produced water, spent sorbents used to remove impurities from natural gas (e.g., glycols, amines, solid desiccants), and backwash used to the clean filters for reuse. Backwash and other wastewater may be managed in the same pits and tanks as produced water, but spent filters and sorbents are expected to be handled as a separate waste stream for disposal. 3.1.3. Well Maintenance A variety of maintenance operations (“workover operations”) may be required during the operational life of a well to maintain or enhance production. It may be necessary to first stop the flow of production fluids from the formation by pumping a high-density fluid similar to the completion fluids down the well to control formation pressure. If the well is damaged, it may be necessary to repair or replace downhole equipment. If the hydrocarbon formation becomes plugged with sand, paraffin or other fine grained materials, it may be possible to use a combination of hot liquids, acids and other physical or chemical treatments to remove the accumulations. If production cannot be restored, other options may include re-stimulating the well through hydraulic fracturing, plugging the wellbore with cement and re-completing the well in an upstream location, or re-drilling the well into a deeper production zone. Because many of these operations are similar to those conducted for well installation and completion, many of the wastes generated are also similar. One distinct workover waste is pipe scale that forms when oversaturated minerals precipitate out of produced water and adhere to the inside of production tubing and gathering lines. Scale buildup can clog pipes and cause significant drops in production. Some types of scale can be readily removed through a combination of acid solution or mechanical scrapers. The dissolved or dislodged scale will then become incorporated into settled solids or other waste streams. However, some types of scale are highly recalcitrant and may require equipment to be removed from service in order to dislodge the scale. In some cases, the equipment may be disposed with the scale still intact. Given the difficulty of removal, this type of scale is expected to be managed and disposed as a separate waste stream. Oil and Gas Production Rates Both the U.S. DOE Energy Information Administration (EIA) and the Independent Petroleum Association of America (IPAA) compile statistics on crude oil and natural gas production in the United States. Available data show that onshore production occurs in 34 states, though a minority of states account for the majority of production. Table 3-1 summarizes the states with the greatest number of active (i.e., producing) wells. These data were drawn primarily from The Distribution of U.S. Oil and Natural Gas Wells by Production Rate (U.S. DOE, 2018a). This dataset does not currently include any data for Idaho, Illinois or Indiana and so total well counts were drawn from relevant state agency Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-6 websites. The number of gas wells in these three states were drawn from the EIA data series, Number of Producing Gas Wells (U.S. DOE, 2018b) and the number of oil wells was calculated by subtraction. Table 3-1. Estimated Number of Active Wells in 2016 by State Rank State Total Number of Wells Number of Oil Wells Number of Gas Wells 1 Texas 309,970 174,654 135,316 Percent of All Wells 29.5% 2 Oklahoma 83,977 36,002 47,975 8.0% 3 Pennsylvania 80,426 11,489 68,937 7.7% 4 Kansas 74,050 51,326 22,724 7.1% 5 New Mexico 58,338 17,837 40,501 5.6% 6 West Virginia 56,971 3,704 53,267 5.4% 7 Colorado 54,987 8,885 46,102 5.2% 8 California 52,848 48,865 3,983 5.0% 9 Ohio 45,154 13,124 32,030 4.3% 10 Louisiana 36,777 19,003 17,774 3.5% 11 Wyoming 33,783 10,090 23,693 3.2% 12 Illinois 32,100 32,064 36 3.1% 13 Kentucky 19,705 5,145 14,560 1.9% 14 North Dakota 14,396 13,942 454 1.4% 15 Michigan 13,595 3,689 9,906 1.3% 16 Utah 12,622 4,192 8,430 1.2% 17 Arkansas 11,671 1,875 9,796 1.1% 18 New York 10,873 3,120 7,753 1.0% 19 Montana 10,173 4,645 5,528 1.0% 20 Virginia 8,161 9 8,152 0.8% Top 20 States 1,020,577 1,049,560 463,690 481,781 556,917 567,779 97.2% All U.S. Wells 100% Total Illinois Wells: https://www.dnr.illinois.gov/OilandGas/Pages/AboutOilAndGasInIllinois.aspx The IPAA estimated there were a total of 1,072,973 active wells (578,167 oil and 494,806 natural gas) in 2016 (IPAA, 2017). These counts differ somewhat from EIA estimates, though the overall order of magnitude is the same between the two sources. The IPAA does not provide a similar breakout by state, which prevents more in-depth comparisons. Counts by well type are complicated by the fact that individual wells can produce a mixture of crude oil and natural gas. For record-keeping purposes, wells are often designated as either oil or gas based on which is produced in greater quantities.5 Thus, well counts do not provide a reliable proxy for the total production of oil or gas in individual states. Table 3-2 summarizes data on oil and gas production in the highest producing states from the EIA data. 5) One barrel of oil is equivalent to approximately 6,000 ft3 of natural gas. Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-7 Table 3-2. Estimated Crude Oil and Natural Gas Production in 2016 by State. Rank State Crude Oil Production Volume Percent of (MMBL) Total Volume Natural Gas Production Volume Percent of State (Bcf) Total Volume 1 Texas 1,176 36.4% Texas 8,126 24.8% 2 North Dakota 378 11.7% Pennsylvania 5,313 17.0% 3 California 186 5.8% Alaska 2,868 10.1% 4 Alaska 179 5.5% Oklahoma 2,468 7.8% 5 Oklahoma 154 4.8% Wyoming 1,848 6.7% 6 New Mexico 146 4.5% Louisiana 1,708 5.6% 7 Colorado 116 3.6% Colorado 1,702 5.5% 8 Wyoming 73 2.2% Ohio 1,440 5.2% 9 Louisiana 56 1.7% West Virginia 1,375 5.0% 10 Kansas 38 1.2% New Mexico 1,285 4.1% 11 Utah 31 0.9% Arkansas 823 2.2% 12 Montana 23 0.7% North Dakota 609 2.1% 13 Ohio 22 0.7% Utah 365 1.0% 14 Mississippi 20 0.6% Kansas 243 0.7% 15 Illinois 9 0.3% California 196 0.7% 16 Alabama 8 0.3% Virginia 120 0.5% 17 West Virginia 7 0.2% Michigan 101 0.4% 18 Pennsylvania 6 0.2% Alabama 100 0.3% 19 Michigan 6 0.2% Kentucky 92 0.3% 20 Arkansas 5 0.2% Montana 52 0.2% Top 20 States 2,640 82% Top 20 States 30,834 95% Total U.S. 3,232 100% Total U.S. 32,592 100% MMBL = Million Barrels Bcf = Billion Cubic Feet Crude Oil Production: https://www.eia.gov/dnav/pet/PET_CRD_CRPDN_ADC_MBBL_M.htm Natural Gas Production: https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FGW_mmcf_a.htm The IPAA estimated national production to be 3,231 MMBL of crude oil and 32,800 Bcf of natural gas (IPAA, 2017), which align well with EIA estimates. It is clear from EIA data that production varies considerably among states and that a greater number of wells does not always translate to higher production. One reason is the age of the wells. Although wells can be re-stimulated by various means to recover output, production will inevitably decrease over time as the local reserves are depleted. Wells that no longer produce more than 10 BL of oil or 60,000 ft3 of natural gas per day are classified as marginal wells (or “stripper wells”). The Interstate Oil and Gas Compact Commission (IOGCC) estimated that in 2016 a total of 396,023 oil wells and 381,334 gas wells had marginal production. These wells account for around two-thirds of active wells in the country and nearly all of the wells in some states. Altogether, marginal wells are estimated to produce between 284 and 404 MMBL of crude oil and 1,880 and 2,760 Bcf of natural gas, around 10% of nation-wide production (U.S. DOE, 2016a,b; IOGCC, 2017; IPAA, 2017). While the number of marginal oil wells and associated production have remained steady over the last two decades, the number of marginal gas wells and associated production Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-8 have nearly doubled (IPAA, 2017). This change reflects broader trends in the oil and gas industry over this time period. Table 3-3 provides a comparison of industry statistics from 2016 with those reported in the 1987 Report to Congress. Table 3-3. Change in Industry Statistics, 1985 to 2016 Source Source: U.S. EPA (1987a) Source: IPAA (2017) % Change EPA IPAA IPAA IPAA Total Active Wells 842,000 889,970 1,072,973 +20.6% Wells Completed per Year 70,000 70,796 14,379 -79.7% Petroleum Production (MMBL) 3,650 3,274 3,231 -1.3% Natural Gas Production (Bcf) 16,100 19,600 32,600 +66.3% MMBL = Million Barrels Bcf = Billion Cubic Feet This comparison shows that production of oil has remained stable over the past three decades, while production of natural gas increased substantially. The increase in natural gas production is attributed primarily to the adoption of directional drilling and hydraulic fracturing that allowed access to oil and gas trapped in black shale and other unconventional formations. In 2016, a total of 14,379 wells were completed. Over the same time period, the number of active horizontal wells increased by around 6,200 (IPAA, 2017; U.S. DOE, 2018a). Figure 3-3 shows the location of the major tight oil and shale gas plays across the United States. It is notable that many states with these plays are also those with the greatest annual production volumes (e.g., Texas, Oklahoma, Pennsylvania). A simple comparison of production statistics at two points in time does not provide a complete picture of how the industry changed in the intervening time. The production boom in the early 2000s resulted in a dramatic increase in the number of oil and gas wells drilled, though the annual number of wells never Figure 3-3: Major Shale Gas and Tight Oil Plays reached the same levels reported in Source: (U.S. DOE, 2018d) 1985. Over the same period, oil and gas production increased substantially. The increased production has been maintained so far, even as the number of new wells decreased in recent years. Figure 3-4 provides a year-by-year comparison of the number of wells completed each year and the annual production volume over the past two decades (IPAA, 2017; U.S. DOE, 2018c,d). Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-9 35,000 3,500 30,000 3,000 25,000 2,500 20,000 2,000 15,000 1,500 10,000 1,000 5,000 500 0 0 Year Production 40,000 40,000 35,000 35,000 30,000 30,000 25,000 25,000 20,000 20,000 15,000 15,000 10,000 10,000 5,000 5,000 0 Production Volume (Bcf) Gas Wells 4,000 Completed Wells Production Production Volume (MMBL) Completed Wells Oil Wells 40,000 0 Year Figure 3-4: Comparison of Well Completion and Production Volume, 1997 to 2017. The recent decline in the number of drilled wells reflects advances in the available technology and drilling techniques. Between 2000 and 2016, the fraction of wells in operation that are horizontal increased from 1% to 12% (U.S. DOE, 2018a). Horizontal wells provide greater contact between the well and the reservoir rock and so are capable of producing greater volumes of product. In 2017, only 1% of vertical wells were able to produce more than 100 BL/day of crude oil, but 30% of horizontal wells exceeded this production volume (U.S. DOE, 2018e). The growing number of horizontal wells have allowed sustained production growth even as the well count has fallen. Current forecasts predict that production from tight oil and shale gas formations will continue to grow into 2019, driven in part by recent discoveries in the Permian basin (U.S. DOE, 2018f; U.S. DOI, 2018). Waste Generation Rates The exploration and production of crude oil and natural gas generates substantial quantities of waste compared to many other industrial sectors. However, information on waste volumes is not routinely collected nationwide. Although some states collect and maintain data on the wastes generated within their respective boundaries, the methods and metrics used to collect these data are not uniform (U.S. GAO, 2012). In addition, some states exempt certain wastes from regulation and so data may not be available. This makes it difficult to compare and aggregate data on a wider scale. Some recent efforts have been made to provide estimates for individual wastes. The U.S. DOE Argonne National Laboratory (ANL) estimated that 21,000 MMBL of produced water were generated in 2007 (U.S. DOE, 2009), while the Ground Water Protection Council (GWPC) estimated a total of 21,180 MMBL were generated in 2012 (GWPC, 2015). However, these estimates do not fully capture the increased production in unconventional formations or the more recent decline in the number of wells completed each year. Therefore, these estimates may no longer be fully representative. The most recent national-scale estimates for many E&P wastes are from the American Petroleum Institute (API, 2000). API used data from a 1995 survey to calculate relationships between production Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-10 metrics (e.g., volume of oil produced) and the volume of waste generated. These relationships were then used to scale waste volumes based on various production metrics in 2000. For the purposes of this discussion, EPA used the same relationships to update waste volumes based on more recent production metrics. Table 3-4 summarizes the estimated waste generation in 2016. Table 3-4. Estimated E&P Waste Generation in 2016 Density (Tons/BL) Waste Type Drilling Fluids/Mud Drill Cuttings Stimulation/Workover Fluids Settled Solids Pipe Scale Produced Water Natural Gas Treatment Residuals Wastewater Treatment Residuals Hydrocarbon Bearing Soil and Debris Total 0.21 0.23 0.18 0.24 0.18 0.18 0.31 0.22 Volume (MMBL) Mass (MM tons) Percent of Total 93.4 19.6 33.5 7.5 7.2 1.3 2.7 0.64 Insufficient Data Available 24,942 4,452 0.31 0.06 249 77 1.8 0.4 0.4% 0.2% < 0.1% < 0.1% 25,330 100% 4,559 97.7% < 0.1% 1.7% < 0.1% MMBL – Million Barrels Use of the same scaling factors assumes that the relationships between production and waste generation have remained constant over time. However, the volume of waste generated by a given well is related to the type of hydrocarbon produced, the geographic location of the well, and the method of production (U.S. GAO, 2012). Therefore, shifts in overall type, location and age of wells can all affect this relationship. API estimated that, between 1985 and 1995, the average volume of produced water generated for every barrel of oil increased by 1.4 barrels as a result of growing population of aging wells in conventional formations (API, 2000). Since that time, the existing fleet of wells has continued to age and newer wells have been drilled in unconventional formations. These new wells tend to be drilled a greater distance through the producing formation and generate greater quantities of produced water early in the life of the well. As a result, current estimates may underestimate waste volumes to some degree. Nevertheless, these estimates still provide a reasonable comparison of relative waste volumes. Produced water is the E&P waste generated in the largest volume by far and this is unlikely to change. However, this does not mean that the other wastes are not as environmentally significant. Economic Structure Under RCRA, EPA is generally prohibited by statute from considering cost as a basis for whether regulation is necessary. However, the Agency is also required by executive order to quantify both the expected costs to the industry and benefits to human health and the environment from significant regulatory actions. This information allows the Agency to transparently assess and communicate the potential impacts of different actions to the public. Therefore, EPA assembled available data on the economic structure of the oil and gas industry. The North American Industry Classification System (NAICS) is the standard used by federal agencies to classify business establishments for the purpose of collecting, analyzing and publishing statistical Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-11 data related to the economy. The NAICS numbering system employs a 2 to 6-digit code that designates individual industrial sectors with increasing specificity based on the number of digits. The entire upstream oil and gas subsector is captured by the 3-digit code NAICS 211: Oil and Gas Extraction. The industry can be further subdivided into two 6-digit NAICS national industries: NAICS 211120: Crude Petroleum Extraction and NAICS 211130: Natural Gas Extraction. The information in this section is profiled at the 3-digit NAICS industry segment level. A number of organizations collect data on the economic conditions of the oil and gas industry and the contributions to the U.S. economy. For example, both the Bureau of Economic Analysis and the EIA collect data on the consumption and production of crude oil and natural gas and petroleum products, and the Federal Reserve Bank reports capacity utilization for the industry which measures how much capacity is being used of the total available capacity for production. A variety of peer-reviewed publications have analyzed the market structure, pricing, and concentration of the industry and there are a variety of sources used to assess the financial conditions of firms in the industry (i.e., SEC filings are available to assess the financial conditions of public companies). The following text provides a brief summary of available data on revenue and employment in the oil and gas industry. 3.4.1. Revenue Revenue data provide insight into the economic conditions of the oil and gas industry over time. Economic Census data are widely used to assess economic impacts as a percentage of revenue; however, these data are only collected every five years. Table 3-5 summarizes the available data on revenue in the Oil and Gas Extraction sector from the Economic Census for years 2007 and 2012. Data for the 2017 Economic Census are not slated for release until September 2019. Table 3-5. NAICS 211: Oil and Gas Extraction – Revenues Year Number of Establishments Value of sales, shipments, receipts, revenue, or other business (Million $) Average sales, shipments, receipts, revenue, or other business per establishment (Million $) 2012 2007 6,735 6,260 $310,960 $255,105 $46.1 $40.7 17.96% 11.74% Percent Change Source: https://www.census.gov/programs-surveys/economic-census/data/tables.html Between 2007 and 2012, the overall Oil and Gas Extraction sector experienced increases in revenue. EIA predicts natural gas and natural gas liquids have the highest projected production growth (U.S. DOE, 2019). The EIA predicts strong growth in U.S. natural gas production, but points towards heightened uncertainty regarding future oil supply and demand as a result of international market conditions, though EIA’s natural gas price projections depend more on domestic factors that drive supply, including domestic resource and technology assumptions, than on international conditions (U.S. DOE, 2019). 3.4.2. Employment The Economic Census collects data on the number of individuals that are employed at both the firm and establishment level. The U.S. Census Bureau (Census) considers an establishment to be a single Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-12 physical location where one predominant activity occurs, while a firm can have multiple establishments defined by a unique Employer Identification number issued by the Internal Revenue Service. The Economic Census provides extensive statistics on U.S. businesses, but the data are only collected every five years, most recently in 2012. The Census also collects the Statistics of U.S. Businesses series annually, which provides more limited data. Table 3-6 reports the number of firms, establishments and employees by employment size in the NAICS 211: Oil and Gas Extraction sector by using data from the Statistics of U.S. Businesses, which has historical data available back to year 1988. Table 3-6. Oil and Gas Extraction - Employment in 2016 Employment Size Number of Firms Number of Establishments 0-4 3,913 3,919 6,562 5-9 818 830 5,306 10-19 427 446 5,562 Employment 20-99 396 481 14,203 100-499 98 246 14,858 500+ 108 1,408 75,649 Total 5,760 7,330 122,140 Source: https://www.census.gov/data/tables/2016/econ/susb/2016-susb-annual.html Combining the data on employment with the number of reported firms provides an estimate of the average employment per firm. In 2016, the Oil and Gas Extraction sector employed an average of 21 employees per firm. The Small Business Administration defines small firms as having 1,250 or fewer employees for both NAICS 211120: Crude Petroleum Extraction and NAICS 211130: Natural Gas Extraction. By this standard, the percentage of small firms and establishments in the industry is high. Over 99 percent of firms are considered small, while over 80 percent of establishments are considered small. 3.4.3. Resolution of Available Data EPA is not aware of any publicly-available sources that provide economic data for this industrial sector at a finer resolution than the establishment or firm level. There is little information available about the number and type of wells, pits, tanks and other relevant operational units associated with each establishment or firm. Therefore, it is difficult to know how the costs of regulatory requirements for specific types of operational units, such as wells, pits, or tanks, would be distributed across the industry. Any evaluation of potential economic impacts would require extrapolation and estimation of cost and revenue based on some assumptions about the number and type of operating units present. This represents a major source of uncertainty in any analysis. Management of Exploration, Development and Production Wastes Section 3: Industry Overview 3-13 4. Waste Management Wastes that are generated over the course of E&P operations must be managed prior to disposal or reuse. There are a variety of options for onsite or offsite management available. The purpose of this section is to describe the most common methods to store and dispose of waste that fall under the jurisdiction of RCRA. Although a large fraction of wastes are ultimately disposed through injection wells, either for disposal or enhanced recovery (GWPC, 2015), these specific practices are not addressed in this document. EPA attempted to assemble specific information from state permits for the various waste management units (e.g., pits, landfills, land application facilities); however, a comprehensive review of these permits was not feasible at this time. The number of permits and associated documentation is enormous and often requires foreknowledge of individual wells or waste management units to access each one (e.g., well number, county). Therefore, this section instead aims to use available information to provide a general overview of different waste management practices for E&P waste and some of the major environmental design considerations for each. Pits Pits (alternately referred to as “impoundments,” “ponds,” “lagoons” or “sumps”) are generally excavated areas of land where waste is placed for temporary storage or ultimate disposal. These pits are typically constructed below grade, though there may be berms or dikes around the perimeter that extend above the ground surface. The size of the pit is dictated primarily by the volume of waste that will be generated. Therefore, pits that service multiple wells will tend to be larger. There is limited information available on the current number of pits in operation. Between 1996 and 2002, EPA estimated a total of 28,000 pits at E&P sites across Colorado, Montana, North Dakota, South Dakota, Utah and Wyoming (U.S. EPA, 2003). In 2019, Colorado reported a total of 3,426 active pits (CODNR, 2019), which is a substantial decrease from the 10,950 pits previously estimated in this state by EPA despite the increase in shale gas production over the past decade. It is unknown whether a similar decrease has occurred in other states. The literature suggests that multi-well pits are becoming more common and may include water recycling systems to provide water for drilling and completion of subsequent nearby projects (Carpenter, 2014). Regardless of location, pits have a number of design considerations based on the types of materials managed and applicable state regulations. Pits may be constructed with compacted local soils or lined with a range of different materials, such as concrete, compacted clay or high-density polyethylene. Liners may be installed to prevent infiltration of stored fluids into the underlying soil. This prevents loss of materials (e.g., fresh water) or release of contaminants to the surrounding environment (e.g., produced water). Figure 4-1 provides an example of two separate pits with a geomembrane liner. The larger pit contains drill cuttings, while the smaller pit contains drilling fluid that will be circulated into the well. Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-1 Figure 4-1: Pits with Visible Liners. Source: Left: Bill Cunningham, U.S. DOI Geological Survey; Right: U.S. EPA Most pits are open to the air, which may allow birds and other wildlife to come in direct contact with the waste. These pits may not attract birds during the drilling process due to human activity and noise. However, once the drilling rig and other equipment are removed from the well pad, animals may be attracted to the water and insects entrapped in the pit fluids (U.S. DOI, 2009). A number of states recommend or require netting or another type of barrier around pits to prevent access by wildlife and intruders. Fencing and netting may be constructed from a range of materials, such as chain link, barbed wire, and fabric. Figure 4-2 provides examples two pits with both fencing and netting. Figure 4-2: Pits with Fencing and Netting. Source: Left, U.S. DOI Fish and Wildlife Service; Right, U.S. EPA State regulations specify over 20 different types of pits based on various factors, such as the duration the pit will be in use (e.g., temporary, permanent), the stage of operations (e.g., drilling, production) or the materials that will be managed (e.g., fresh water, produced water). However, the terminology used by different states can overlap and conflict. Therefore, EPA focused on broad categories of pits for the purposes of this general discussion. Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-2 4.1.1. Reserve Pits Reserve pits are used for the storage of the wastes (e.g., drill cuttings, spent drilling fluid) generated during well installation. The primary wastes that are managed in these pits include drill cuttings and spent drilling fluids. However, used completion fluids and other miscellaneous, smaller-volume wastes may also be placed in these pits. Reserve pits are temporary and only active until the well has been installed and the wastes have either been removed or prepared for disposal in place. Installation time varies considerably but is generally on the order of a few weeks to a few months. Most states require closure of reserve pits within 6 to 12 months of completion of drilling so the total length of time a reserve pit may be present on a site is expected to be between 6 and 15 months. As a result of the relatively short lifespan of these pits, it is anticipated that the majority of units currently in operation have been constructed in compliance with current state regulations. However, reserve pits that service multiple wells on a single pad may operate for longer periods of time. It is unknown how many reserve pits are currently in operation. Under the assumption that there is one reserve pit associated with each well drilled, there could have been as many as 14,379 new reserve pits created in 2016 (IPAA, 2017). The actual number is likely to be lower, as some sites will use tanks or centralized pits. Pits are sized primarily based on the total length that will be drilled, which can vary considerably based on the formation and the type of well. Horizontal wells can generate anywhere between 30 and 70% more cuttings than vertical wells (Johnson and Graney, 2015). A study conducted by the U.S. DOI Fish and Wildlife Service reported that pits in two areas of Wyoming range in size from 10,200 to 24,000 ft2 (U.S. DOI, 2009). A recent study in Texas estimated the average area of reserve pits designed for long residence times to allow solids to settle out was 75,000 ft2 with a volume of 25 MBL (Redmon et al., 2012). SkyTruth reviewed aerial photography around permitted drilling locations to identify the number and size of pits across Pennsylvania. Table 4-1 provides the estimated number of pits and associated areas identified by this effort. The same effort also tracked the presence of pits over time and found that nearly 80% of the pits identified were no longer present three years later. This indicates that many of the pits identified onsite are likely to be shorter-lived reserve pits. Table 4-1. Summary of Pit Sizes in Pennsylvania Year Number of Pits Average Area (ft2) Median Area (ft2) 2005 11 1,998 1,132 2008 237 3,415 1,834 2010 581 11,211 6,568 2013 529 24,780 20,374 Source: https://www.skytruth.org/2014/10/pa-drilling-impoundments-2005-2013/ When well installation is completed, the free liquids in the reserve pit are generally removed to the extent practicable, either through pumping or evaporation. The remaining solids are a mixture of drill cuttings and residual solids left by the drilling fluids that may include additives, such as bentonite clay and barite. Any residual liquids that are intermingled with these solids may be stabilized with lime or fly ash prior to disposal. Pits may be closed in different ways depending on state requirements. In some states, the waste solids may be disposed in place by folding the liner over the dewatered drill cuttings Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-3 and backfilling the pit with soil. In other states, the cuttings and any liner must be removed and disposed of at an offsite facility approved by the state to accept E&P wastes. 4.1.2. Production Pits Production pits are used for the storage of wastes generated during well production. The primary waste managed in these pits is produced water. These pits will also gradually accumulate sludge at the bottom of the pit from settling of suspended solids and precipitation from produced water. Other smallervolume wastes may also be placed in these pits. These pits can be present throughout the lifespan of a well, which may extend anywhere from 15 to 50 years. EPA identified one state that reported the number of production pits. The California State Water Board conducted an inventory of pits that contain produced water, as well as the numbers that are both lined by the state. Table 4-2 provides a summary of reported active production pits as of January 2019. Table 4-2. Number of Active Production Pits in California Region Total Lined Unlined Central Coast 41 32 9 Los Angeles 76 76 0 Central Valley 561 31 530 2 0 2 680 139 541 Santa Ana Total Source: https://www.waterboards.ca.gov/water_issues/programs/groundwater/sb4/oil_field _produced/produced_water_ponds/ EPA identified little information about the typical size of production pits. However, pits associated with horizontal wells are expected to be much larger than other pits to accommodate the large volumes of produced water generated. EPA previously estimated that between 0.3 and 1 million gallons (7.1 to 23.8 thousand barrels) of water can be produced in the first 10 days after hydraulic fracturing, primarily from the flowback of injected water (U.S. EPA, 2016a). Due to the large volume of waste produced over a short period of time, such large pits may not always be economical to construct onsite. Centralized pits in the Permian Basin of Texas have been reported to be as large as 320,000 ft2 (McEwan, 2012). When production is complete, the liquids in the production pit are removed to the extent practicable. This may be accomplished through pumping, evaporation or discharge to ground or surface water. Liquids that are removed from the pits may be disposed or recycled for use at nearby wells. It has been estimated that hydraulic fracturing produced about 660,000 MBL of produced water for disposal in 2017 and of that, about 14% was treated and reused (Presley, 2018). Additional treatment may be applied to solid residuals (e.g., sludge) including thickening, stabilization, and dewatering processes prior to disposal. These solid residuals may be sent to a landfill, land spread, or incinerated (Morillon et al., 2002). Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-4 4.1.3. Other Pits There are a number of other specific pits that may be present at E&P sites. Some of these pits may be used to hold specific wastes, such as well blowdown or gas processing condensate. Other pits may be used for specific events. For example, emergency pits are used to contain excessive or unanticipated amounts of fluids generated during an emergency situation in the drilling or operation of a well, such as a well blowout or a pipeline rupture. Flare pits are intended to collect any liquids that remain after hydrogen sulfide Figure 4-3: Flare Pit. Source: U.S. DOI Fish and Wildlife Service and other gases are burnt off. Figure 4-4 shows an example of a flare pit. These pits are not intended for the prolonged storage of waste and are typically emptied as soon as possible after use. There is little information available on the number of these pits. However, because of the specific uses for these pits, the size tends to be much smaller than reserve or production pits. Tanks Tanks are prefabricated structures used both to separate waste from product and to store wastes prior to transport offsite. Tanks may be installed aboveground or below the surface. The size of individual tanks typically ranges between 100 to 1,000 BL, depending on the rate of production. The number of tanks needed at a site will vary based on the quality and quantity of crude oil, natural gas and produced water generated. If a well produces high-quality oil and little gas or water, a site may only require a single tank to store oil. However, a site with heavy oil and substantial gas or water production may need anywhere from two to ten tanks to separate and manage the various products and wastes. Multiple tanks at E&P sites are commonly grouped together in batteries that include the tanks, flow lines and the other equipment necessary to manage produced fluids. Colorado reported a total of 1,561 active tank batteries (CODNR, 2019). Under the assumption that the prevalence of tank batteries is similar among states and there is an average of three tanks per battery (i.e., separator, heater-treater, storage), EPA scaled the number reported for Colorado for each state based on the number of active wells and estimated there to be around 90,000 tanks across the country. However, this number may be higher in high-producing regions. Regardless of the number of tanks, there are a number of design considerations that depend on applicable state regulations and both the quantity and quality of the oil produced. Tanks and the associated piping may be constructed from a variety of materials, such as steel, fiberglass or polyvinyl chloride. Each material has specific strengths and weaknesses based on the temperature, fluid corrosiveness, service pressure, duration of production, and operating costs at a given site. Steel can sustain high-pressure flow and is easily welded, but can be prone to corrosion when exposed to highly saline fluids (e.g., produced water). Although steel may be coated to protect against corrosion, these treatments may not be effective at extreme temperatures (Heintz, 2005). Fiberglass tanks are light Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-5 and resistant to corrosion, but are less conductive and so may be more susceptible to damage from lighting strikes if not properly grounded (Wood, 2014). Polyvinyl chloride is a relatively inexpensive option, but is not well-suited for high-pressure flow. Tanks may leak during operation as a result of damage (e.g., puncture), degradation (e.g., corrosion) or human error (e.g., overfilling). Therefore, secondary containment is often required to prevent releases from migrating from the initial point of release before the spill can be identified and addressed. A example design recommendation is for secondary containment to be large enough to hold 1.5 times as much fluid as is stored in the largest tank; however, alternate volumes may be specified by state regulations. Containment may be constructed from range of materials. Figure 4-5 shows examples of tank design with secondary containment. Figure 4-4: Tanks with Secondary Containment. Sources: Left, U.S. EPA; Right, UWCE (2005) 4.2.1. Closed-Loop Drilling Closed-loop drilling fluid systems are an alternative to reserve pits in which the flow path is not open to the atmosphere. In a closed-loop system, a series of tanks are used together with specialized equipment (e.g., screen shakers, hydrocyclones, centrifuges) to separate drilling fluid from drill cuttings and other solids. This process minimizes the amount of fluid retained on the waste solids and maximizes the amount of fluid recycled back into the drilling process. Minimizing the volume of waste solids through fluid removal results in less waste ultimately disposed (Redmon et al., 2012). Prior to disposal this dried waste may be stored in piles or dumpsters prior to transport offsite. Use of closed-loop drilling is often considered a best management practice (NMEMNRD 2000; TXRRC, 2001). 4.2.2. Production Tanks When a well begins to produce salable quantities of oil or gas, additional tanks are required to separate the product from the waste. The most common types of production tanks are separator tanks (e.g., wash tanks, settling tanks, gun barrel tanks) that use density differences to separate crude oil, natural gas and produced water; heater-treater tanks that use heat from the sun or another source to rapidly break down emulsions of oil and water; and storage tanks that hold the separated materials until ready for Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-6 transport for sale or disposal. The composition of a tank battery may change over the life of the well. Tanks may be added or removed to support changes in the volume of oil and produced water generated. As the nature of production changes, different specialized equipment will need to be brought in to meet different needs. For example, a well may initially have sufficient natural pressure to maintain flow. However, as the natural pressure falls, it may be necessary to add equipment, such as a hydraulic lift to maintain production. Figure 4-6 shows an example of the types of production tanks that may be present at E&P sites. Figure 4-6: Diagram of Production Tanks. Source: Courtesy of ESD Simulation Training, Inc. Tanks are neither intended nor suited for the disposal of waste. Therefore, at the end of the useful life, all tanks should be cleaned out and transported offsite. This involves draining fluids from the tank and removing any solids (i.e., sludge) that have accumulated on the tank bottom. The tanks that are removed may be disposed, reused or recycled depending on the state of the tank. 4.2.3. Modular Large Volume Tanks Modular large volume tanks (MLVTs) are freestanding aboveground tanks assembled in the field with sectional frame that supports a synthetic liner that provides primary containment for fluids. These types of tanks are more easily dismantled after use for transport to another location. However, because of the greater number of seams present in the tank structure, there may be greater risk of catastrophic failure if the tanks are not properly assembled and maintained. These tanks have been used to hold both fresh water for use in hydraulic fracturing operations and wastewater from E&P operations, though some states may place restrictions on the materials that may be stored in these tanks. Figure 46 shows some examples of modular tanks. Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-7 Figure 4-5: Modular Large Volume Tanks. Source: Tipton (2013) Land Application Land application is the general practice of disposing of waste on surficial soils. Some states use different terminology (e.g., land treatment, landfarming) to distinguish between application of different waste types or method of application (e.g., surface spread, tilled). The primary purpose of this practice is to promote decomposition of organic compounds. After application, the soil may be periodically tilled to amend the soil with nutrients or aerate the waste to promote decomposition. Figure 4-8 shows some examples of how E&P wastes may be land applied to the soil. Land application may occur onsite around the well pad or offsite. Offsite disposal may occur at state permitted facilities or on private land with the agreement of the landowner. It has been reported that farmers have been paid to allow application of E&P waste to lower-productivity rangeland or pasture. It is unknown what effects the application of E&P waste may have on the quality and productivity of the soil; this is an area Figure 4-6: Land Application of E&P Wastes. of ongoing research (OCES, 2017). Source: OCES (2017) There are a number of design considerations for land application units based on the waste disposed and where it is applied. Onsite applications typically occur only once and are generally limited to cuttings drilled with water-based fluids. Offsite application may occur multiple times with a wider range of wastes. States may place restrictions on the types of waste applied based on measured level of organics (e.g., total petroleum hydrocarbons [TPH]), salts (e.g., chloride), and radioactivity (e.g., radium) or based on the types of waste considered likely to have high levels of these constituents (e.g., oil-based drilling fluid, horizontal cuttings). Restrictions may also be placed on where the waste is applied to limit the potential for offsite migration (e.g., permeable soil, steep slope, flood zones). Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-8 EPA did not identify any formal records of application onsite or offsite to private land. Offsite land application is addressed in the regulations of at least eleven other states, though the location and number are not publicly available (U.S. DOE, 2006). The size of land application facilities is often unknown. Facilities identified in Texas range between 12 acres divided into 4 separate cells and 517 acres divided into 17 cells. One permit in Kansas shows an area of 160 acres divided into 10 separate cells (KCC, 2012). Other Offsite Disposal There are a number of options for disposal of E&P waste at offsite facilities. Costs vary depending on the location of the disposal facility, the method used for disposing of the waste, the type of waste, and the extent of competition in the local or regional area. Although the costs of disposal are an important consideration, transportation costs, laboratory fees, and other associated costs will also influence the decision. Generally, operators will not be inclined to transport waste more than 50 to 75 miles unless no other alternatives are available (U.S. DOE, 2006). The availability of offsite facilities dedicated to E&P wastes varies by state. A 2006 report conducted by the Argonne National Laboratory found that eight states with higher oil and gas production had a dedicated network of offsite disposal facilities overseen by the state regulatory agency (i.e., Arkansas, Colorado, Louisiana, New Mexico, Oklahoma, Texas, Utah, Wyoming). Seven states with less oil and gas production did not have the same degree of infrastructure (i.e., Alabama, Michigan, Mississippi, Nebraska, North Dakota, Pennsylvania, West Virginia). The remaining states had no industry-specific infrastructure (i.e., Alaska, Arizona, California, Florida, Illinois, Indiana, Kansas, Kentucky, Missouri, Montana, New York, Ohio, Tennessee, South Dakota, Virginia) (U.S. DOE, 2006). It is likely that states without dedicated facilities for E&P wastes rely on the existing infrastructure for disposal of other solid wastes (e.g., municipal solid waste landfills) to manage E&P wastes. 4.4.1. Landfills Offsite landfills may be used for the disposal of certain E&P waste solids. These permitted landfills may accept waste from a range of sources (e.g., municipal solid waste landfills) or may be dedicated solely to E&P wastes. The wastes must meet the acceptance criteria for the landfill and so the composition of the waste may determine the type of landfill selected. States have reported rejecting drill cuttings for use as alternate daily cover as a result of high TPH and oily residue (ASTSWMO, 2015). The number of offsite landfills that accept E&P wastes is not known. However, based on a review of state regulations and websites, EPA is aware of both commercial and municipal solid waste landfills accepting certain E&P wastes. Recent reports indicate that there is a trend in states with high oil and gas production toward dedicated landfills (Karidis, 2017). In Texas, multiple new disposal facilities have recently been constructed that include composite liners, leak detection systems, and groundwater monitoring (Sandoval, 2018). Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-9 4.4.2. Other Treatment and Disposal Facilities Other treatment and disposal facilities may be used for the management of E&P waste solids and liquids. This broad category of facilities is differentiated from landfills because the wastes sent to these facilities are not permanently disposed on the ground surface. These facilities may be owned and operated by one or more oil and gas operators (“centralized facilities”) or by entities other than the oil and gas operator (“commercial facilities”). Some examples of treatment include crude oil reclamation and wastewater treatment. Treatment can result in the reclamation of a useful product that might be sold (e.g., crude oil), but can also generate new wastes that may be more concentrated than the original E&P waste and must be disposed appropriately (e.g., water treatment residuals). Examples of disposal include underground injection, percolation and evaporation. These facilities may use pits and tanks, similar to those found near the wellsite, to store waste prior to treatment or disposal. Figure 4-9 provides examples of an evaporation pit with sprayers used for disposal of produced water (left) and a centralized pit used for storage of produced water prior to water treatment (right). Figure 4-7: Treatment and Disposal Facilities. Sources: Left, Tipton (2013); Right, U.S. DOI (2013) Information on the total number of different treatment and disposal facilities that accept E&P wastes is limited. Between 1996 and 2002, EPA identified 36 centralized disposal facilities across Colorado, Montana, North Dakota, Utah and Wyoming (U.S. EPA, 2003). EPA more recently estimated that up to 74 centralized water treatment facilities may accept waste liquids from hydraulic fracturing (U.S. EPA, 2016a). The Texas RRC provides a current list of 107 permitted “commercial recycling and surface disposal facilities,” more than half of which are located in the Permian Basin. Many of these facilities are dedicated to reclamation or recycling of waste, though 28 are also permitted for disposal of treatment residuals. Several of the permits reviewed from Texas note the that residual wastes may be disposed through onsite burial, deep well injection, or burial in RCRA Subtitle C facilities. These permits also provide specifications for the size of pits, along with detailed requirements for waste acceptance, constructing, waste testing, operating, groundwater monitoring, and closure. Table 4-3 provides examples of the types and sizes of pits present at select facilities in the Permian Basin. Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-10 Table 4-3. Examples of Disposal Pit Sizes in the Permian Basin Facility Name Facility Size Howard County Treatment, Recovery and Disposal Facility 144 Acres Wishbone Facility Not Provided Midland SWD/Sludge and Disposal Facility 39.2 Acres Pit Type Number Pit Area (ft2) Capacity (MBL) Receiving 3 99,500 94.3 Collecting 1 130,000 76.1 Disposal 5 798,000 5,100 to 6,700 Receiving 2 4,000 4.3 Disposal 10 Various Sizes 280 to 11,000 Collecting 3 6,000 to 88,200 1.6 to 23.7 Disposal 4 1,500 to 448,200 900 to 2,900 Source: https://www.rrc.state.tx.us/oil-gas/applications-and-permits/environmental-permit-types-information/commercialsurface-waste-facilities/commercial-recyclingdisposal-permits-list/ Beneficial Use Beneficial use is a broad term that describes the practice of utilizing non-hazardous materials in a productive fashion as an alternative to disposal. State programs generally have an administrative mechanism in place that allows a generator to submit a request for a specific beneficial use. The relevant state agency reviews the request to determine whether the proposed use is appropriate. Beneficial use determinations are often made on a case-by-case basis after consideration of factors, such as the benefit provided, the long-term performance of the use, and any potential risks to human health or the environment (U.S. EPA, 2013). In some states, the structure for these determinations is clearly defined and tools, such as application forms and detailed guidance, have been made available to assist the applicants. In other states, regulatory language is written broadly and the specific data collection and demonstration requirements are not specified upfront. In 2013, the Association of State and Territorial Solid Waste Management Officials (ASTSWMO) conducted a survey of state management practices. A total of 11 states of the 28 that responded to the survey indicated they had approved various beneficial uses, such as drill cuttings (road base, concrete, grading), drilling fluid (concrete), sludge (road application), and produced water (dust suppressant, deicing) (ASTSWMO, 2015). Other uses that have been reported for produced water in some western states include livestock watering, irrigation, and streamflow supplementation (U.S. DOI, 2011). Approval for these and other uses is often predicated on the use meeting certain criteria. States have reported rejecting proposed uses because of unsuitable composition, either physical (e.g., grain size) or chemical (e.g., oil and grease, chloride, radium, sulfate) (ASTSWMO, 2015). However, there is little publicly available information about the frequency at which different states have approved beneficial uses, the volumes that have been diverted to these uses, and where the uses occur. Management of Exploration, Development and Production Wastes Section 4: Waste Management 4-11 5. Waste Characterization EPA conducted a literature review on the composition and environmental behavior of wastes generated during well exploration and production operations. This information is needed to characterize the potential magnitude of exposures that may result if wastes are released into the environment. As part of this review, EPA assembled data for multiple types of wells (e.g., oil, coal bed methane, geothermal) into an E&P constituent database. The majority of identified data are for oil and gas wells in non-coal formations. These are the most numerous wells drilled across the country, both historically and currently. These wells were also the primary focus of Onshore Oil and Gas Human Health and Environmental Risk Assessment (U.S. EPA, 1987). Therefore, the review of data in this document focused on wastes from these wells. Further discussion of the approach to assemble and review the data are provided in Appendix B (Constituent Database). Each of the following subsections summarize the available data for an individual waste type. Where feasible, EPA calculated summary statistics for the concentration and activity of inorganic elements, organic compounds and radioisotopes (“constituent levels”) in each waste type. When factors that might affect waste composition were identified, EPA separated out the data to facilitate comparison and discussion. In particular, EPA focused on potential differences between the wastes from horizontal and vertical wells as a proxy for conventional and unconventional formations to understand whether and to what extent hydraulic fracturing might affect waste composition. EPA did not compare wastes from individual formations because it would further subdivide the available data and make meaningful comparisons more difficult. The summary statistics and comparisons presented in this document are intended to provide the Agency’s current understanding of constituent levels based on available data, which in some cases are limited in quantity and geographic coverage. Even if the statistics do not capture the full variability of each waste, the calculated values still provide useful information on the possible magnitude of constituent levels in each waste, the relative constituent levels among different wastes, and where data gaps still exist. Spent Drilling Fluid Drilling fluids (also referred to as “drilling muds”) are the materials used during well installation to cool and lubricate the drill bit, control pressure within the borehole, seal drilled formations to prevent the loss of drilling fluid into the formations and the influx of water from the formation into the borehole (i.e., annulus), and to transport drill cuttings to the surface. These fluids are pumped downhole through a hollow drill string and exit through nozzles in the drill bit back to the surface through the space between the drill and the walls of the borehole. Once back at the surface, drilling fluid is mechanically separated from the drill cuttings with equipment such as filter belts or centrifuges and treated to the extent necessary for reuse. The fluids are considered spent once the composition is no longer suitable for reuse, when changing geological conditions in the well require a new fluid formulation, or when the wells are complete (U.S. EPA, 1987d). Spent drilling fluids are assumed to be managed primarily as an aqueous waste, though there are known instances where the fluids are evaporated or otherwise Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-1 dewatered prior to disposal as a solid. However, few data were identified for the residual solids and so EPA did not separately discuss leachate from this waste. 5.1.1. Bulk Concentration Drilling fluid is initially composed of a base fluid (e.g., water), solids (e.g., bentonite, cellulose) and other chemical additives. The majority of drilling fluids use water as a base (API, 2000). As a result, the majority of available data are for water-based fluids. However, oil- and synthetic-based fluids are still used to address specific drilling scenarios, such as clay formations that could expand in the presence of water. Additionally, compressed gases (e.g., air, nitrogen) have been used to drill in certain carbonate and coal formations. Thus, EPA incorporated the limited data available for other drilling fluids. However, due to the near absence of data on these other fluid types, it is not possible to draw any separate conclusions about the resulting wastes. Although the composition of the fluids is precisely engineered prior to use, the fluids will mix with cuttings and formation water during drilling. This can introduce contaminants into the fluid that are then transported back to the surface. The scope of treatment is often limited to restoring the physical properties of the fluid necessary for reuse (U.S. DOI, 2011). As a result, recycling has the potential to result in further accumulation of contaminants in the fluid. Inorganic Elements EPA identified a total of four studies that measured inorganic elements in drilling fluid. Three of these studies drew samples from vertical wells in at least eight states (U.S. DOE, 1979; API, 1987; U.S. EPA, 1987d). EPA did not identify information that could be used to further weight the data to obtain a more representative national distribution, such as the volume of waste generated in each state. Therefore, data from each state were weighted equally. One other study drew samples from horizontal wells in Pennsylvania (Shih et al., 2015). Table 5-1 presents the 50th and 90th percentile summary statistics of available data for inorganic elements in drilling fluid. Table 5-1. Inorganic Elements in Drilling Fluid (mg/L) Constituent Arsenic Barium Boron Chloride Chromium Copper Lead Manganese Molybdenum Nickel Sodium Strontium Zinc Vertical Wells Horizontal Wells n 50th 90th n 50th 90th 5/8 8/8 8/8 8/8 4/8 4/8 2/8 8/8 6/8 2/8 8/8 8/8 5/8 0.01 1.3 0.85 2,000 0.05 0.01 0.07 0.19 0.13 0.05 2,100 4.1 0.07 0.02 4.9 6.1 33,000 0.16 0.03 1.0 5.6 0.20 0.15 16,000 223 0.20 10 / 12 32 / 32 32 / 32 35 / 35 13 / 21 12 / 20 12 / 13 32 / 32 11 / 13 13 / 19 33 / 33 35 / 35 18 / 25 0.03 23.8 2.5 17,000 0.25 0.17 0.05 2.9 0.11 0.20 11,400 63 0.09 0.18 1,810 15.1 89,000 1.3 0.53 0.30 13 0.41 0.39 33,900 1,558 1.7 n = Number of Samples Detected / Total Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-2 Concentrations from horizontal wells are generally higher than those from vertical wells. However, it is difficult to determine whether all of the observed differences are significant. The vertical dataset consists primarily of single samples from various states, which are unlikely to capture the full variability of any formation. The horizontal dataset shows there can be considerable variability within individual formations. At the same time, the horizontal dataset consists entirely of unfiltered samples. Additional constituent mass from solids suspended in solution could overestimate differences when compared with filtered vertical samples. Despite these uncertainties, the data still provide useful information that can be used to better understand the sources constituent mass and the potential differences between wastes from vertical and horizontal wells. Barium exhibits the greatest proportional increase in concentration between the two datasets. If total suspended solids (TSS) are the source of high measured concentrations, then there must be a solid that is enriched in barium. Cuttings from the formation are likely to have similarly enriched concentrations of other common elements, such as iron and manganese. Another potential source of barium in drilling fluid is barite (BaSO4). Barite is a common and high-density additive to drilling fluid. Industry-grade barite is typically greater than 90% BaSO4 (U.S EPA, 1985). The low solubility of the barite mineral will keep most barium from dissolving into solution and so could contribute to disproportionately high barium concentrations. If barite is the source of high barium concentrations, there should be a relationship between TSS and barium. Figure 4-1 presents a graph of the relationship between TSS and barium in the samples from Shih et al. (2015). 100000 R² = 0.00 Barium (mg/L) 10000 1000 100 10 1 0.1 Total Suspended Solids (mg/L) Figure 5-1: Relationship Between Barium and TSS in Spent Drilling Fluid There is no relationship between barium and TSS; the highest barium concentrations correspond to some of the lowest TSS concentrations. Therefore, barite is not the primary source of barium in these samples. It is more likely that the suspended barite settled out of solution (“barite sag”). The other potential sources of dissolved barium are the water used as a base fluid and the formation water that mixes with drilling fluid in the borehole. The median barium concentration in formation water reported by Shih et al. (2015) is 1,010 mg/L. This is orders-of-magnitude higher than concentrations in either surface water and surficial groundwater, which rarely exceed 0.3 mg/L (ATSDR, 2007). Thus, formation water is the most likely source of barium in the drilling fluid from horizontal wells. Another notable difference between vertical and horizontal wells is lead, which is the only constituent with higher concentrations measured in vertical wells. This may only be the result of small sample size, as the higher summary statistics are driven by a single sample. A similarly high sample is also present in the horizontal dataset, though it does not exert the same influence on the distribution. In both cases, the highest concentration is an order of magnitude greater than the remaining samples. There are a Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-3 number of possible sources for lead. Naturally-occurring sulfide deposits can contain high concentrations of lead, zinc and other metals. Some of these deposits are known to be located alongside hydrocarbon-bearing formations (Kharaka et al., 1987; Leach et al., 2010). Another possible source is the materials used to construct the wells. One compound, commonly known as “pipe dope,” is used to seal pipe joints and can contain more than 30% lead by weight (Kahn, 2011). This lead may leach into the drilling fluid as it circulates through the well (NRC, 1983). There is not enough information available to determine the source of the higher lead in these samples. However, this highlights the need to understand not only drilled formations, but also the drilling practices to fully understand potential waste composition. Organic Compounds EPA identified two studies that measured the organic compounds in drilling fluid. One study drew samples from vertical wells in seven states (API, 1987). EPA did not identify information that could be used to further weight the data to obtain a more representative national distribution, such as the volume of waste generated in each state. Therefore, the data from each state were weighted equally. One study drew samples from horizontal wells in one state (Shih et al., 2015). Table 5-2 presents the 50th and 90th percentile summary statistics of the available data for organic compounds in spent drilling fluid. Table 5-2. Organic Compounds in Drilling Fluid (mg/L) Constituent Vertical Well Horizontal Well n 50th 90th n 50th 90th Benzene 1/6 0.003 0.007 6 / 15 0.003 0.05 Toluene 3/7 0.005 0.01 7 / 15 0.008 0.20 Ethylbenzene 1/6 0.003 0.005 1/1 0.009 Xylene 0/0 1/1 0.11 -- n = Number of Samples Detected / Total A majority of both vertical and horizontal data are non-detect. As a result, median concentrations often reflect a detection limit. Horizontal data have a higher detection frequency despite similar detection limits and have higher detected concentrations. This indicates that prolonged contact with formations with high-organic content may result in greater accumulation of organic compounds. However, further conclusions about the magnitude of any differences are limited by the amount of data available. Radioisotopes EPA identified two studies that measured radioactivity in spent drilling fluid (Shih et al., 2015; PADEP, 2016). These studies collected samples from horizontal wells in one state. Samples were only analyzed for radium isotopes because the lower solubility of other radionuclides were expected to result in dissolved activities far lower than radium (PADEP, 2016). Table 5-3 presents the 50th and 90th percentile summary statistics of the available data for radium in drilling fluid. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-4 Table 5-3. Radioisotopes in Spent Drilling Fluid (pCi/L) Horizontal Well Isotope n 50th 90th Radium 226 28 / 28 90.6 1,863 Radium 228 28 / 28 18.3 400 n = Number of Samples Detected / Total The data show that both median and high-end activities of 226Ra and 228Ra are clearly elevated in spent drilling fluid from horizontal wells. Radium does not serve a function in the fluid and so is not intentionally added, though it might be a contaminant present in additives. EPA identified two studies that separately sampled the solid fraction of some drilling fluids (WVDEP, 2013; PADEP, 2016). The studies collected samples from horizontal wells in two states. These solids are expected to be a mixture of various additives along with some residual drill cuttings. In addition to radium, the samples were measured for uranium and thorium because of the greater potential for these radioisotopes to be present in the solid phase at comparable activities (PADEP, 2016). Table 5-4 presents the 50th and 90th percentile summary statistics of available data for radioisotopes in the solids from drilling fluid. Table 5-4. Radioisotopes in Residual Solids from Drilling Fluids (pCi/g) Horizontal Isotope n 50th 90th Uranium 235 2/9 0.06 0.10 Uranium 238 8 / 14 0.84 1.1 Radium 226 14 / 14 1.3 3.5 Radium 228 14 / 14 0.33 1.8 n = Number of Samples Detected / Total Radium activities in the solids phase are substantially lower than the associated fluids from the same study, despite prolonged contact between the two media. Reported 226Ra activity appears to be higher than the parent 238U, which might indicate an outside source of radium in these samples. However, as noted by PADEP (2016), 226Ra activities measured directly by gamma spectroscopy can be biased high when radium and uranium are both present at similar levels because current instruments cannot fully distinguish the energy signatures of 226Ra and 235U. The authors made no attempts to account for this interference in the reported data. If 226 Ra and 238 U are in approximate equilibrium (i.e., no major outside source or sink of radium), then there should be some relationship between the magnitude of excess excess 235 U activity and 226 Ra in each sample. Figure 5-2 presents the relationship between 235 U and 226 Ra based on the raw gamma measurements. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-5 - 238U (pCi/g) 5 4 3 R² = 0.80 The strong relationship indicates that a majority of excess 226Ra activity can be attributed to interference from 235U during measurement. Thus, 226Ra in these samples is likely to be near equilibrium with 238 U. 226 226Ra After adjustment for interference, Ra activities all fall below the upper bound of 4.2 pCi/g measured in 2 surface soil (U.S. DOE, 1981a). It is unclear why 1 exposure to high-activity fluids does not result in enriched solids. It is possible that high dissolved 0 solids in the fluids compete for binding sites on the 0 0.1 0.2 0.3 0.4 0.5 surface of the solids and force the radium to remain 235U (pCi/g) in solution (Sturicho et al., 2001; IAEA, 2014). These Figure 5-2: Relationship Between 235U and results indicate that additives and other suspended Excess 226Ra in Residual Solids from Drilling solids are not the primary source of radium in spent Fluid drilling fluid. This is further corroborated by a comparison of total and dissolved activities in formation water samples reported by PADEP (2016), which found dissolved activities to be only 2% lower on average. The potential sources of dissolved radium are the water used as a base fluid and the formation water that mixes with the drilling fluid within the borehole. The median activity in formation water reported by Shih et al. (2015) is 1,680 pCi/L 226+228Ra. This is several orders of magnitude greater than activities typically found in either surface water or surficial aquifers, which generally have a combined radium activity less than 5 pCi/L (ATSDR, 1990; Szabo et al., 2012). Therefore, formation water is the most likely source of activities reported in drilling fluid. EPA identified one additional sample of solids from drilling fluid taken from Colorado; however, this sample was solidified prior to disposal in the landfill (CHDT, 2015). Although drilling fluids are typically disposed of as aqueous waste, high-solids fluids may be solidified prior to disposal on land. This sample is greatly enriched in radium, with a 226Ra activity of 91 pCi/g and corresponding 238U activity of only 0.2 pCi/g. The report provides no discussion on the materials used in solidification of the waste. Materials commonly used for other wastes include cement and fly ash. Like most materials drawn from the earth, these pozzolanic materials contain some radium. However, neither of these materials have been reported to have such disproportionately high radium activity (U.S. EPA, 1979; UNSCEAR, 2000). The more likely source of radium is drilling fluid, which has been shown to have disproportionately high radium activities that could easily support the activity measured in the solidified sample. If residual drilling fluid is used to hydrate a pozzolanic material, then the dissolved radium could be incorporated into the solidified mass. Alternately, if the drilling fluid were allowed to evaporate before solidification, this could also concentrate radium in the remaining solids. This suggests that waste management practices have the potential to result in higher activities than predicted based on measurement of solids alone. This represents a major source of uncertainty in the available data. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-6 5.1.2. Summary – Spent Drilling Fluids This review highlights the complexities of deep well drilling. Potential sources of constituent mass include additives to the drilling fluid, leaching from equipment, and mixing with the formation. In the borehole, drilling fluid is exposed to reducing conditions under elevated temperature and pressure. The fluid is then brought back to the surface where it is exposed to oxygen before being cycled through the borehole again. This process can be repeated multiple times before the fluid is spent and ultimately disposed. The impact of shifting environmental conditions on drilling fluid during use have not been well-explored in the literature. Therefore, any conclusions must be drawn from measurements of spent drilling fluids. The available data indicate that a major source of constituent mass in water-based drilling fluids is mixing of the drilling fluid with formation water in the borehole. Constituent levels (i.e., concentrations and activities) measured in formation water are sufficient to support levels measured in drilling fluid, though other sources previously mentioned also have the potential to contribute additional constituent mass. Available studies did not characterize produced water from the same wells, so it is not possible to determine the actual extent that mixing occurred in any sample. The data available to characterize this waste are limited. Some studies only provide individual data points and so do not capture variability in any of the formations sampled, while others provide multiple samples for only a single formation. This makes it difficult to draw conclusions about the typical composition of this waste or the exact magnitude of any differences between vertical and horizontal wells. However, if the primary source of constituent mass is mixing with the formation as expected, then the relative composition of drilling fluids should mirror that of the formation water. The extent of mixing will depend on the distance drilled and the number of times the fluid is cycled through the borehole. Horizontal wells tend to be drilled greater distances through the formation than vertical wells. Thus, if constituent levels are higher in formation water from these wells, the same should be true of the drilling fluid. Available data indicate that the majority of dissolved constituent mass remains in solution during waste management. There was no apparent enrichment of residual solids from the spent fluids. However, one sample of solidified waste had disproportionately high radium activity that suggests contributions from another source. It is possible that constituent mass from the fluids is retained on residual solids through solidification, evaporation or another process. If so, this could result in much higher constituent levels than predicted based on solids data. This represents a major source of uncertainty in the current data. Drilling Solids Drilling solids are a mixture of the wastes managed in reserve pits and tanks. Drill cuttings, which are the rock and minerals that are ground up within the borehole and brought to the surface during well installation, are typically the largest component of drilling solids. Cuttings are separated from the drilling fluid at the ground surface, but may subsequently be mixed with spent drilling fluid and other lower-volume wastes prior to disposal. The quantity and composition of the waste depends on the conditions at the drilling site. Without information about the drilling and waste management practices at a site, it is difficult to attribute measured constituent mass to a particular source. Thus, this discussion focuses on drill cuttings, but considers mixed drilling solids where data are available. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-7 The composition of a single formation can vary considerably and deeper wells, like those necessary to access hydrocarbon-bearing formations, inevitably traverse a number of distinct formations. As a result, it can be difficult to define representative concentrations for cuttings. In recent years, the widespread adoption of directional drilling has resulted in a substantial increase in the total volume of drill cuttings generated. Depending on the diameter of the borehole, the depth to target formation and the lateral distance drilled, the additional horizontal cuttings have been estimated to represent anywhere between 30 and 70% of the total volume generated (Johnson and Graney, 2015). The black shale in these cuttings has been studied extensively in the literature. Therefore, this discussion focuses on the composition of black shale, but considers cuttings from above the hydrocarbon formation where data are available. 5.2.1. Bulk Composition Black shale is a type of sedimentary rock characterized by higher organic carbon that typically ranges between 1% and 30% of the rock mass (Meyers and Mitterer, 1986). Extractable hydrocarbons in these rocks originate from the decomposition of high-molecular weight organic matter known as kerogen that decompose slowly at a specific range of temperatures and pressures found in some deep geological formations. During decomposition, a variety of simple and complex organic compounds can form alongside the economically-significant hydrocarbon deposits. The inorganic fraction of black shale is composed of silicates and other minerals that form through deposition and diagenesis (Ketris and Yudovich, 2009). EPA identified several studies that evaluated the major mineral composition of black shales from California (Brumsack, 2005), Kentucky and Ohio (Perkins et al., 2008), Mississippi (Rimmer, 2004), and Pennsylvania (Balashov et al., 2015; Phan et al., 2015; Stuckman et al., 2015). Silicon dioxide (SiO2) present in minerals such as albite, illite and quartz is the largest component of most samples, with content typically around 50% of the total mass. Other major components are aluminum, barium, calcium and iron oxides, which each account for up to 20% of the mass in individual samples. International studies that analyzed samples from China, Egypt, India, Namibia, Peru and Poland all reported similar ranges (El-Anwar, 2016; Piszcz-Karaś et al. 2016). Inorganic Elements EPA identified three primary studies that measured inorganics in black shale formations. Ketris and Yudovich (2009) assembled data on black shale from around the globe. Reported values reflect samples grouped into separate distributions based on lithology (e.g., carbonate) and weighted based on the frequency that each lithology was expected to occur. Chemak and Schreiber (2014) assembled data on gas-producing black shale in the United States. Reported values reflect equally-weighted data from the Antrim, Bakken, Eagle Ford, Marcellus, New Albany, Utica and/or Woodford formations. U.S. DOI (2017) also assembled data on black shale from around the globe. Reported values reflect summary statistics calculated from the raw data by EPA.6 The different approaches used to aggregate data introduce some uncertainty and prevent further aggregation of the data from the different studies. Therefore, the focus of this comparison is to identify major trends in the data and not to provide a 6) EPA used data analyzed with either non-destructive methods or digestion methods with hydrogen fluoride to ensure reported values provide a best estimate of total mass. For most constituents, this was the majority of available data. The data were not further weighted based on lithology or other metrics. Non-detect samples were omitted because the high detection limits relative to the detected concentrations often overwhelmed summary statistics. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-8 definitive distribution for any element. The inter-quartile range was used for the comparisons because it diminishes the effects of outliers that could skew higher percentiles and because these were the only summary statistics provided by Ketris and Yudovich (2009). Table 5-5 provides a comparison of these different data sources for elements reported in two or more sources. Table 5-5. Inorganic Elements in Black Shale (mg/kg) Constituent n Antimony Arsenic Barium Beryllium Cadmium Chromium Cobalt Copper Lead Lithium Manganese Mercury Molybdenum Nickel Selenium Silver Strontium Thallium Uranium Vanadium Zinc 1,930 4,190 15,100 7,810 2,260 21,900 21,000 25,740 20,520 4,520 19,600 1,420 18,480 23,160 1,650 9,000 16,650 2,710 8,400 25,200 13,300 Global Black Shale1 25th 50th 2.0 10 270 1.0 2.0 50 10 35 10 15 200 0.20 6.0 40 3.0 0.40 100 0.50 4.0 100 60 5.0 30 500 2.0 5.0 96 19 70 21 31 400 0.27 20 70 8.7 1.0 190 2.0 8.5 205 130 75th n 11 80 800 3.0 12 160 30 150 40 50 800 0.60 60 140 30 2.4 300 10 25 400 300 20,537 19,321 61,125 37,829 17,520 56,921 51,878 45,659 49,534 28,340 50,150 207 35,685 61,500 8,589 19,619 53,288 4,512 15,511 62,924 47,115 Global Black Shale2 25th 50th 0.43 7.0 200 1.9 0.55 30 5.2 20 15 26 110 0.06 7.0 20 1.4 0.45 109 0.60 1.5 70 51 1.0 20 440 2.5 1.5 70 10 50 27 55 252 0.60 15 41 3.1 1.0 200 0.96 3.8 137 105 75th 2.6 53 730 7.0 12 100 18 100 46 110 500 4.5 40 92 8.0 3.0 500 4.3 15 210 200 U.S. Gas-Producing Black Shale3 n 25th 50th 75th -39 186 --199 169 -----303 236 ----314 312 187 -21 92 --54 5.0 -----27 37 ----15 194 64 -37 181 --84 14 -----74 88 ----39 329 108 -87 324 --119 21 -----116 149 ----204 506 340 1) Source: Ketris and Yudovich (2009) 2) Source: U.S. DOI (2017) 3) Source: Chermak and Schreiber (2014) n = Number of Total Samples The two global datasets are intended to reflect the same set of materials. Thus, any differences result from variability among the formations sampled and the methods used to weight the data. Differences are most pronounced for elements with the fewest data points (e.g., antimony, mercury, selenium). Yet the considerable overlap between the distributions of many elements provides some confidence that many of these elements have been adequately characterized. Based on available data, many constituents in black shale are substantially higher than typical surface soils reported in Geochemical and Mineralogical Data for Soils of the Conterminous United States (U.S. DOI, 2013b), often by an order of magnitude or more. The metalliferous nature of black shale is welldocumented in the literature. Various studies have reported elevated levels of antimony, arsenic, cadmium, chromium, copper, lead, mercury, molybdenum, nickel, selenium, silver, thallium, thorium, uranium, vanadium and/or zinc (e.g., U.S. DOI, 1970, 1983; Ketris and Yudovich, 2009). These high concentrations cannot be attributed to unique properties of any individual basin (Tourtelot, 1979; Scott, Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-9 2017). Instead, high levels result from the complex interplay of multiple factors, which include the rate that organic matter deposited on the seafloor, the depth of the water column, both the extent and duration of anoxic conditions, and local water chemistry. Under the anoxic conditions present during the deposition of organic matter, redox-sensitive elements are sequestered from the water onto organic matter or reduced sulfur (Arthur and Sageman, 1994; Chemak and Schreiber, 2014; Scott et al., 2017). Many elements in gas-producing shale are similar to global shale, but a few are noticeably higher. One key difference between these datasets is the amount of total organic carbon (TOC) present. Median TOC in gas-producing samples is 9.7%, while the median in samples from U.S. DOI (2017) is 1.7%. Constituents with an affinity for organic matter would be expected to concentrate in gas-producing shales. This is true for uranium, the element with the greatest apparent increase relative to global shales. The relationship between uranium and TOC can be so strong that gamma radiation has been used in the field as a proxy for TOC during well surveys (Lüning and Kolonic, 2003) and black shale formations were previously considered as potential sources of uranium ore (U.S. DOI, 1961). Other elements measured in gas-producing shale known to associate with organic matter include chromium, molybdenum, nickel, vanadium and zinc (Meyer and Robb, 1996; Wilde et al., 2004; Ross and Bustin, 2009; Scott et al., 2017). Moderate but consistent increases are seen in the data for molybdenum and vanadium, but the remaining constituents are not readily distinguishable from global shale. The absence of apparent differences might be attributed to other sources of these elements, particularly reduced sulfur. Arsenic, chromium cobalt, nickel and zinc are also known to associate with sulfidic minerals, such as pyrite (Meyer and Robb, 1996; Ross and Bustin, 2009; El-Anwar, 2016). The amount of free hydrogen sulfide in the water column is not directly linked to the amount of organic carbon that accumulates in a formation. Because higher concentrations of sulfur-bound elements may occur in regions of both high and low organic carbon, similar concentrations are possible in all formations. Thus, it is reasonable that all of the constituents associated with reduced sulfur are similar among different sample sets. The constituent with an apparent decrease in gas-producing shale is barium. Under anoxic conditions, barium can remobilize and, as it diffuses upward and encounters waters with sulfate, reprecipitate as barite (Henkel et al., 2012). This upward migration of barium can lead to greater stratification within the black shale. As a result, barium enrichment can occur above black shale deposits to a greater degree than other elements (Dean et al., 1984; Schijf, 2007; Henkel et al., 2012; Engle and Rowan, 2014). Thus, barium is not necessarily depleted from the formation, but may be located in more concentrated lenses within and above the shale. This spatial variability may contribute to observed differences, as samples collected from horizontal cuttings or exposed rock outcrops have greater potential to miss more isolated barite deposits. Overall, the similarities between datasets indicate that global black shale data can provide a useful estimate of potential concentrations for many elements in gas-producing black shale, though elements with a strong affinity for organic matter may occur at even higher concentrations. The concentrations in black shale may not be the same as the drilling solids that are ultimately disposed at the ground surface. During drilling and subsequent storage, black shale will be blended with surrounding rock Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-10 facies, which may dilute the higher inorganic concentrations found in the black shale. It is known that many of the samples reflected in Table 5-5 were collected from drill cuttings (as opposed to targeted outcrop samples) and so this blending is already reflected to some degree. The cuttings may also be mixed with spent drilling fluid and other wastes that can alter the overall composition of the waste. To better understand the extent to which these solids may differ from the initial cuttings, EPA reviewed available data on drilling solids. EPA identified a total of four studies that measured inorganic elements in drilling solids collected from pits and tanks. Three drew samples from vertical wells in eleven states (Freeman and Deuel, 1984; API, 1987; U.S. EPA, 1987d). EPA did not identify information that could be used to further weight the data to obtain a more representative national distribution, such as the volume of waste generated in each state. Therefore, the data from each state were weighted equally. One study drew samples from horizontal wells, both above and within the hydrocarbon formation, in one state (PADEP, 2016). The horizontal well samples had been stabilized in preparation for land disposal. Table 5-6 presents the 50th and 90th percentile summary statistics of available data for inorganic elements in drilling solids. Table 5-6. Inorganic Elements in Drilling Solids (mg/kg) Constituent Antimony Arsenic Barium Cadmium Chromium Cobalt Copper Lead Manganese Mercury Molybdenum Nickel Silver Strontium Uranium Vanadium Zinc Vertical Horizontal (Above) Horizontal (Within) n 50th 90th n 50th 90th n 50th 90th 2 / 11 11/11 11/11 3 / 11 11/11 11/11 11/11 11/11 11/11 3 / 11 6 / 11 11/11 2 / 11 11/11 0/0 11/11 11/11 2.5 2.1 2,650 0.25 7.3 3.6 8.2 14 125 0.03 1.2 6.3 0.15 68 -8 41 4.3 7.8 6,000 2.7 24 7 17 120 190 0.08 2.9 14 1.3 260 -11 132 14 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 38 / 38 1.8 11 3,215 2.1 25 25 38 25 554 1.0 4.0 61 2.9 283 3.7 121 107 26 17 16,620 16 196 36 55 36 619 2.1 11 90 20 1,124 6.6 209 135 14 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 / 18 18 26 82,050 37 112 24 84 112 235 2.5 50 119 38 1,423 19 12 172 28 38 220,600 70 231 40 128 363 413 6.1 112 261 56 6,184 49 173 280 n = Number of Samples Detected / Total Concentrations from vertical wells are generally lower than those from both sets of horizontal wells. Some differences may arise because the vertical dataset consists primarily of single samples from various states, which are unlikely to capture the full variability of any formation. The horizontal datasets show there can be considerable variability within individual formations, but not enough to explain the order of magnitude difference observed between the vertical and horizontal data. The more likely cause is the different analytical methods used to measure constituent concentrations. Vertical samples were Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-11 prepared for analysis with acid digestion (HNO3 + HCl),7 while horizontal samples were analyzed directly with non-destructive methods. Non-destructive methods measure the entire constituent mass within the sample matrix, while digestion methods measure the constituent mass that can be liberated from the matrix with a combination of heat and acid (Gaudino et al., 2007). Some fraction of a recalcitrant waste may not dissolve during digestion. This can result in an underestimation of elements incorporated in the mineral lattice. These uncertainties limit the conclusions that can be drawn about differences between vertical and horizontal wells. Yet, similar trends are seen in both datasets. In all three sets of data, the median concentrations of barium are substantially higher than the black shale reported in Table 5-5. The magnitude and frequency of higher concentrations indicates that a majority of the barium does not originate from drill cuttings. The other large-volume waste typically stored together with cuttings is drilling fluid. With modern equipment, fluid retention on cuttings is typically below 15% by mass (U.S. EPA, 2000d). The dissolved concentrations of barium measured in fluids are generally less than 1,800 mg/kg of water (Table 5-1).8 In addition, the range of concentrations of barium and strontium measured in drilling fluid are similar, while those in pit solids are orders-ofmagnitude different. Thus, retention of drilling fluid alone does not account for disproportionately high barium. The high ionic strength of the fluid also makes it unlikely that the high barium results from selective sorption onto the surface of cuttings. Therefore, the most likely source of barium is mixing of cuttings with barite that settles out of the drilling fluid. Industry-grade barite is typically > 90% BaSO4 (U.S EPA, 1985). The amount of barite used depends on the fluid density required to counteract increasing pressure within the formation and has been reported to range anywhere from 15 to 62% of the total mass of the fluid (NRC, 1983). Only a small fraction of barite is expected to adhere to cuttings during separation of fluids and cuttings at the surface, but greater accumulation is possible if spent fluids are stored together with cuttings. At higher drilling fluid densities, it would only require about 0.5 ft3 of drilling fluid mixed with each 1 ft3 of shale cuttings to achieve the 90th percentile barium concentration measured in the horizontal drilling solids.9 At a minimum, drilling fluid must be used in equal volumes to the cuttings removed in order to fill the void in the borehole, though greater volumes are often be necessary. Thus, based solely on mass balance, barite in spent drilling fluids could account for high barium concentrations in the final waste. This accounts for the higher concentrations in horizontal solids relative to vertical solids, as higher water densities may be required to drill under the greater pressure in these formations. Although barite is predominantly barium sulfate, it can also contain inorganic contaminants present alongside barite deposits. Previous analyses of barite have shown the additive can contain elevated concentrations of arsenic, chromium, cadmium, copper, mercury, lead and zinc (NRC, 1983; Candler et al., 1992; Neff, 2007). EPA previously concluded that veined deposits of barite tend to have higher 7) A mixture of nitric acid (HNO3) and hydrochloric acid (HCl) is commonly used to digest a range of materials, such as organic matter, carbonates, phosphates and iron oxides. An example of a more aggressive acid is hydrofluoric acid (HF), which can be used to digest silicates that comprise a large fraction of some drill cuttings. 8) Assumed fluid density of 1.0 kg/L representative of fresh water to provide a high-end concentration per unit mass. 9) Assumed fluid density of 2.1 kg/L and a shale density of 2.7 kg/L. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-12 concentrations of these inorganic elements than bedded deposits (U.S. EPA, 1996).10 Veined deposits are often found together with sulfide, rare-earth, gold and silver minerals (U.S. DOI, 1958). Many of the contaminants reported in barite are elements that tend to associate with reduced sulfur, which are the likely source of these other inorganics. The Agency previously identified concerns with the potential toxicity of these inorganics to wildlife and, in 1996, finalized limits on the concentrations of cadmium and mercury allowed in stock barite that can be discharged to open waters as part of the Oil and Gas Extraction Point Source Category, Offshore Subcategory; Effluent Limitations Guidelines and New Source Performance Standards (40 FR 10664). However, higher-concentration barite might still be used in onshore drilling, as these wastes are not discharged directly to surface water. To better understand the extent to which barite may affect the composition of drilling solids, EPA compared concentrations in black shale (Table 5-4) and pit solids (Table 5-6). EPA found that the median concentrations of antimony, cadmium, mercury, silver and strontium in horizontal drilling solids are all considerably higher than the median values from the different black shale datasets. This indicates that the addition of barite to drill cuttings might substantially increase concentrations of some inorganic elements. Organic Compounds EPA identified a total of four studies that measured organic compounds in drilling waste. Two drew samples of drilling solids from vertical wells in eleven states (API, 1987; U.S. EPA, 1987d). EPA did not identify any information that could be used to further weight the data to obtain a more representative national distribution, such as the volume of waste generated in each state. Therefore, the data from each state were weighted equally. The remaining two studies drew samples of drill cuttings from horizontal wells, both above and within the hydrocarbon formation, in two states (WVDEP, 2015; Eitrheim et al., 2016). Table 5-7 presents the 50th and 90th percentile summary statistics of the available data for organic compounds in drilling solids/cuttings. Table 5-7. Organic Compounds in Drilling Solids (mg/kg) Compound Benzene Ethylbenzene Toluene Xylene n Vertical Solids 50th 90th 11 / 11 11 / 11 11 / 11 0.03 0.35 1.1 0.59 2.8 3.1 0/0 -- -- Horizontal Cuttings (Above) n 50th 90th 2/3 1/1 1/1 1/1 20 96 58 37 390 Horizontal Cuttings (Within) n 50th 90th 3/5 2/3 3/3 3/3 773 28 58 1,870 32 62 390 438 N = Number of Samples Detected / Total Concentrations in samples from horizontal wells both above and within the formation are substantially higher than those from vertical wells. Horizontal wells tend to be drilled within formations with higher organic content, which could account for the greater concentrations. However, there is additional uncertainty introduced into this comparison by the fact that vertical samples reflect drilling solids and the horizontal samples reflect drill cuttings. Concentrations in vertical samples may be diluted though mixing with other wastes; however, the majority of the waste is still anticipated to be cuttings and so dilution would not account for the orders-of-magnitude difference. The few samples of cuttings from 10) Veined deposits are those that fill cavities or fractures within a pre-existing rock formation. Bedded deposits are those that form as a distinct depositional layer within a stratified formation. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-13 above the horizontal formation have concentrations similar to or lower than from within the formation. It is possible that these cuttings capture black shale that overlays the economicallysignificant target formation. As a result of the sources of uncertainty, few conclusions can be drawn without additional data. Radioisotopes EPA identified only one study that measured radioisotopes in drilling solids from one state (PADEP, 2016). Samples were collected from both above and within a horizontal formation. Each sample had been stabilized in anticipation of land disposal, though the study did not specify how stabilization was achieved. Table 5-8 presents the 50th and 90th percentile of the available data for radioisotopes in drilling solids. To confirm the measured activities, some samples were directly measured with gamma spectrometry and indirectly calculated based on measurement with X-ray fluorescence (XRF) and natural isotope ratios. Where appropriate, both sets of measurements are presented for comparison. Table 5-8. Radioisotopes in Stabilized Drilling Solids (pCi/g) Isotope Uranium 235 Uranium 238 Analytical Method Horizontal (Above) Horizontal (Within) n 50th 90th n 50th 90th (235U) 8 / 38 0.08 0.15 12 / 18 0.18 0.39 γ-ray (234Th) 20 / 38 0.80 1.6 12 / 18 1.2 3.4 γ-ray XRF 37 / 37 1.3 2.2 18 / 18 6.3 17 γ-ray (226Ra) 38 / 38 2.1 3.8 17 / 18 3.8 9.9 Thorium 232* XRF 37 / 37 1.8 2.0 18 / 18 1.4 1.8 Radium 228 γ-ray (228Ac) 38 / 38 1.1 1.3 17 / 18 0.68 0.84 Radium 226 * PADEP (2016) reported 228Ra and 232Th activities that are nearly identical because values were based on ingrowth of the same short-lived progeny (228Ac). Therefore, the 232Th data are not useful for comparison and is not presented. n = Number of Samples Detected / Total The 238U activities in samples calculated from XRF are often higher than those measured with gamma spectrometry. This might indicate that the activities of this isotope measured by gamma spectrometry are biased low. The low energy of 234Th (63.3 keV) has been reported to result in higher counting error compared to other radioisotopes (U.S. DOE, 1981b). Yet some measured 226Ra activities are greater than both measured and calculated 238U activities. As noted by PADEP (2016), 226Ra activities measured directly by gamma spectroscopy can be biased high when radium and uranium are both present at similar levels because current technology cannot fully distinguish the energy signatures of 226Ra and 235U. However, if 226Ra and 238U are in approximate equilibrium (i.e., no major outside source or sink of radium), then there should be a relationship between 235U activity and the magnitude of excess 226Ra measured in each sample. Even if activities measured with gamma spectroscopy are biased low, all of the samples were measured with the same equipment and so should reflect a similar bias. Figure 5-3 presents graphs of vertical and horizontal samples based on the raw gamma measurements and presented on the same scale for comparison. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-14 Above Formation 226Ra - 238U (pCi/g) 16 Within Formation R² = 0.05 R² = 0.70 12 8 4 0 0.0 0.2 0.4 235U 0.6 (pCi/g) 0.8 1.0 0.0 0.2 0.4 235U 0.6 0.8 1.0 (pCi/g) Figure 5-3: Relationship Between 235U and Excess 226Ra in Stabilized Drill Cuttings There is a strong relationship between 235U activity and excess 226Ra in samples collected from within the formation, which is similar to the relationship observed for solids from drilling fluid (Figure 5-2). This indicates that the higher measured 226Ra activity can be attributed to interference from 235U. Thus, radium and uranium are expected to be in approximate equilibrium in these samples. This aligns with data from Eitrheim et al. (2016), which found 226Ra activity in two samples of drill cuttings from within a shale formation to be similar to, but slightly lower than, 238U activity.11 Based on these data, it does not appear that stabilization substantially changed the radioisotope composition of drill cuttings. The drilling fluid from this formation is known to contain elevated radium, but these fluids may not have been retained on the stabilized waste. No information is available on how solidification/stabilization was achieved in these or other samples and so this represents a major source of uncertainty. No such relationship is apparent for samples collected from above the shale formation. There are several outliers of high radium, though removal of these samples only worsens the correlation. The excess radium activity in remaining samples remains flat as 235U increases, which might indicate that radium is depleted in these samples. In contrast, one sample of drill cuttings collected by Eitrheim et al. (2016) from above a shale formation contained 226Ra activity similar to, but somewhat lower than, the 238U activity. There is no single, clear explanation for the variable enrichment and depletion in these drilling solids. Depletion may result from mixing of the cuttings with highly saline drilling fluid. Unlike black shale, these rocks did not form in the presence of saline water, so it is possible that exposure to high salinity may disrupt equilibrium and cause the release of radium to solution. Higher radium activities may result from precipitation of barite out of solution as a result of quickly shifting water chemistry. Samples with elevated radium all exhibit increased barium concentrations in proportion to activity, while the remaining samples exhibit a flat relationship with barium. However, no information is available on how solidification/stabilization was achieved in these or other samples and so this represents a major source of uncertainty. 11) Eitrheim et al. (2016) measured was not necessary. 226 Ra activity through the radon ingrowth method and so correction for interference from Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 235 5-15 U 5.2.2. Leachate EPA identified three studies that measured both inorganic elements and organic compounds in leachate from drilling solids from wells drilled with water-based fluids (API, 1987; U.S. EPA, 1987; LADNR, 1999). No data were identified for radioisotopes. Because of the limited amount of data available for the different types of constituents, EPA did not break the discussion into separate sections. All available samples were collected from vertical wells located in at least thirteen states. The majority of available data are evenly distributed among the different states, but LADNR (1999) reported selected elements for a greater number of samples from Louisiana. The same study also reported samples from wells drilled with oil-based fluids. EPA combined the data without any weighting to compare wastes generated with water- and oil-based fluids. Table 5-9 presents the 50th and 90th percentile of the available data for both inorganic elements and organic compounds in leachate from drilling solids for all constituents that were detected in at least half of samples. Table 5-9. Constituent Levels in TCLP Leachate from Drilling Solids (mg/L) Constituent Vertical (Water-Based) n 50th Aluminum 14 / 26 0.25 Barium 44 / 56 Boron 17 / 24 Cobalt Iron 90th Vertical (Oil-Based) n 50th 90th 1.4 0/0 -- -- 1.9 5.0 124 / 142 2.2 6.5 0.9 2.2 0/0 -- -- 19 / 24 0.02 0.05 0/0 -- -- 22 / 26 2.4 26 0/0 -- -- Lead 40 / 54 0.11 0.88 91 / 142 0.14 0.83 Manganese 26 / 26 2.8 5.5 0/0 -- -- Nickel 16 / 26 0.05 0.09 0/0 -- -- Strontium 24 / 24 3.3 15 0/0 -- -- Zinc 20 / 26 0.78 6.2 0/0 -- -- Toluene 22 / 30 0.03 0/0 -- -- Inorganic Elements Organic Compounds 0.83 n = Number of Samples Detected / Total The available data provide only a few samples for most states and so are unlikely to capture the full variability of individual formations. For example, none of the studies report the equilibrium pH of the leachate. Alkaline wastes can counteract the fixed amount of acid used in the TCLP test increase the pH of solution, which can greatly alter the solubility of some constituents. This makes it difficult to determine what environmental conditions that these samples reflect. Despite the uncertainties, available data allow a comparison of samples drilled with water and oil-based fluids because the majority of samples are drawn from the same region. This comparison shows that both the median and high-end concentrations of barium and lead are similar in magnitude. Limiting the comparison to only samples from Louisiana does not alter this finding. Thus, there is no indication from available data that the type of drilling fluid used substantially alters the leaching behavior of inorganics from the waste. No comparisons could be conducted for any other constituents, including any organic compounds, as a result of a large number of samples with high detection limits. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-16 5.2.3. Volatile Emissions The presence of volatile organic compounds (e.g., benzene) and radioisotopes (e.g., radon) indicate there is potential for releases to the surrounding air. However, EPA did not identify any studies that measured volatile emissions of either type of constituent from drilling solids. Therefore, no conclusions could be drawn about the magnitude or frequency of these releases. 5.2.4. Summary – Drilling Solids There are a number of factors that determine the composition of black shale, which may include the specific environmental conditions present at the time of formation (e.g., extent and duration of anoxia, local water composition), the degree of subsequent evolution (e.g., thermal maturity of hydrocarbons, extent of evaporation), and outside disturbances (e.g., uplift, intrusion from adjacent aquifers). All of these factors result in a high degree of variability among and within source rock. Despite the numerous sources of variability, there is substantial overlap in the concentrations of some elements among the three datasets. This provides some confidence that the range of potential concentrations in black shale has been adequately captured. However, the data also show the potential for higher concentrations of elements with a strong affinity for organic carbon (e.g., molybdenum, uranium) in the subset of gasproducing black shale. Drill cuttings are typically the largest volume waste in drilling solids and so these data may provide a reasonable order-of-magnitude estimate of constituent levels in the associated solids when direct measurements are not available. The available data indicate that management of cuttings generated from both within and above the formation may increase the total constituent mass in the waste. Comingling of drilling fluids with cuttings at the ground surface can result in deposition of barite and other solids onto cuttings, which can in turn increase concentrations of barium and other inorganics. There is currently no evidence that adsorption of dissolved constituent mass from the drilling fluids onto the cuttings is a major source of constituent mass. However, if drilling fluid is incorporated into the solidified/stabilized waste, it may result in much higher constituent levels than predicted based on drilling solids alone. Limited data are available on the extent to which this might occur in the field, which represents a major source of uncertainty with the current data. There are also limited data on the magnitude of releases from drill cuttings or drilling solids through leachate and volatilization. Available studies do not provide key information, such as the equilibrium pH of the measured samples. Because TCLP uses a fixed amount of buffer, wastes with high alkalinity may shift the final pH of the leachate closer to neutral. The solubility of some constituents can change dramatically over a small pH range and so this represents a major source of uncertainty. Thus, while available data provide useful information about the solubility of some constituents, it is difficult to draw conclusions about actual releases when the waste is disposed. Produced Water Produced water is any water drawn from the well as a byproduct of development and production. This includes both the formation water and flowback of any water injected into the well to enhance recovery. The volume of water generated can vary both by formation and individual well. Vertical Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-17 wells, which tend to be sited in more permeable formations, can be relatively dry at first. However, as the pressure within the formation falls as a result of hydrocarbon withdrawal, formation water is more likely to come to the surface together with the oil or gas. It has been reported that these fields can produce more than five times the volume of water in later years (U.S. GAO, 2012). Later in the life of the well, additional water may be injected into nearby wells to increase pressure within the formation and displace remaining oil and gas (“waterflooding”). The injected water migrates through the formation and is then drawn back up through the production well. Horizontal wells, which tend to be sited in less-permeable formations, require water to be injected into the production well to liberate the oil or gas trapped within the rocks prior to the start of production (“hydraulic fracturing”). The injected water will return to the ground surface over a period of weeks to months. During this time, the continued mixing of injected and formation waters results in produced water that transitions from entirely injected water to entirely formation water. Additional water may be injected into a well periodically over the lifetime of the well to further stimulate production. Records of the chemical composition of formation waters are available as far back as the early twentieth century (U.S. DOI, 1911). Initial interest in the composition of produced water was focused on the potential commercial applications for the salt content and the potential to recover precious metals (Rowan et al., 2015). As a result, early analyses were often limited to total dissolved solids (TDS) and certain economically-significant metals. High salinity is a defining feature of produced water from hydrocarbon formations. TDS in formation waters have been measured as high as 500,000 mg/L, over ten times more saline than seawater. Sodium and chloride alone can account for greater than 90% of the dissolved solids in the water (Schijf, 2007; U.S. DOI, 2017). Saline waters occur because the formations have been subjected to elevated temperature and pressure, which cause the evaporation and expulsion of water and further concentration of the remaining constituent mass. If a constituent becomes so concentrated that it exceeds saturation in the remaining water, it may precipitate out in solid deposits. It is possible that greater consolidation and evaporation in the dense formations that require horizontal wells results in higher constituent levels from the concentration of mass into smaller volumes of water. Therefore, EPA focused this review on potential differences in the wastes from vertical and horizontal wells to determine whether and to what degree differences exist. Produced water is assumed to be managed primarily as an aqueous waste and so EPA did not separately discuss leachate from this waste. 5.3.1. Bulk Composition Variable amounts of data are available for each formation, which makes it difficult to aggregate the data in a representative way. To address this issue and to provide a more direct comparison with previous evaluations, EPA mirrored the approach used in the 1987 Technical Support Document (U.S. EPA, 1987d). EPA first grouped each state into zones based on similar geological formations, production activities, and climates. Figure 5-4 presents the production zones used in this evaluation. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-18 Figure 5-4: Oil and Gas Production Zones in the United States (U.S. EPA, 1987d) The full dataset was sampled probabilistically with data from each region weighted based on the relative volumes of gross natural gas and crude oil produced in 2016 by each state from conventional and unconventional formations (U.S. DOE, 2018c,d). All data from a given region was weighted equally in each distribution. Some uncertainty is introduced by the fact that oil and gas production is not always correlated with produced water generation. EPA identified several sources of data on produced water volumes (API, 2000; U.S. DOE, 2009; GWPC, 2015). However, these data are often extrapolated from older reports and do not capture recent increases in production from the spread of directional drilling. In addition, although the amount of produced water generated in some high-producing states may be lower on a per-well basis, the greater number of wells still results in higher overall generation in these states. Therefore, weighting based on oil and gas production is considered reasonable for the purposes of this evaluation. Inorganic Elements EPA identified a number of studies that measured concentrations of inorganic elements in produced water from both vertical and horizontal wells. A summary of data collection efforts is provided in Appendix B (Constituent Database). The summary statistics discussed in this section are based only on the data for formation water. It is clear from the literature that formation water is the primary source of inorganic constituent mass and, although flowback water will contain many of the same elements, concentrations in formation water are typically higher (MSC, 2009; Ziemkiewicz and He, 2015). Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-19 Flowback water can also be highly variable over time as a result of continued mixing with formation water. Thus, formation water provides the most reliable comparison of concentrations. Table 5-10 presents the 50th and 90th percentile of the available data for inorganic elements in produced water from vertical and horizontal wells. The amount of data available varies by constituent. To best capture national variability, EPA limited the constituents presented below to those with data across multiple regions of the country. EPA further refined this list by removing constituents that were measured infrequently in high oil and gas-producing regions, which would skew summary statistics towards those few samples. A far greater number of samples are available for vertical wells. This is because a greater number of vertical wells have been drilled over time, which provided more opportunities to collect samples. Table 5-10. Inorganic Elements in Produced Water (mg/L) Constituent Vertical n 50th Horizontal 90th n 50th 90th Major Ions (mg/L) Bicarbonate 36,060 / 36,060 380 1,731 50 / 52 289 1,281 Bromide 4,048 / 4,057 76 655 186 / 186 915 2,470 Calcium 39,512 / 39,512 1,760 13,846 267 / 267 4,430 20,100 Chloride 39,766 / 39,766 27,500 132,000 291 / 291 71,200 132,000 Magnesium 38,724 / 38,724 365 2,616 259 / 259 580 2,183 Potassium 15,844 / 15,844 141 1,270 205 / 206 326 1,030 Sodium 39,138 / 39,138 15,375 62,678 291 / 291 34,700 52,322 Sulfate 34,665 / 34,702 310 2,789 103 / 161 128 706 Trace Inorganics (mg/L) Aluminum 154 / 185 0.25 7.4 21 / 42 0.21 10 Arsenic 51 / 65 0.01 0.20 -- -- -- Barium 1,579 / 1,593 4.8 171 220 / 256 13 6,470 Boron 1,369 / 1,370 39 115 192 / 195 21 46 Cadmium 58 / 75 0.01 0.02 -- -- -- Cobalt 52 / 67 0.005 0.02 -- -- -- Copper 226 / 254 0.015 1.0 -- -- -- Fluoride 429 / 438 1.5 7.0 -- -- -- Iron 2,212 / 2,244 5.5 63 249 / 250 63 185 Lead 147 / 195 0.05 0.5 -- -- -- Lithium 1,652 / 1,652 5.1 50 -- -- -- Manganese 1,322 / 1,338 0.78 8.6 214 / 223 2.5 14 58 / 73 0.03 0.05 -- -- -- 2,732 / 2,733 60 1,240 252 / 252 737 3,840 212 / 217 0.40 3.3 63 / 69 0.22 2.0 Nickel Strontium Zinc n = Number of Samples Detected / Total Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-20 There is substantial overlap in the range of inorganic concentrations measured in produced water from vertical and horizontal wells. Although concentrations in horizontal wells tend to be higher overall, both well types can have similar high-end concentrations. It is possible the overlap of high-end concentrations reflects saturation of certain elements in formation water. Chloride and sodium have been reported to precipitate out as halite (NaCl) at the high concentrations reported in formation water (PDCNR, 2010; Rowan et al., 2015). In contrast, bromide salts are more soluble than chloride salts and so are less likely to precipitate at the comparatively low concentrations measured in formation water. The data show that horizontal wells have higher median and high-end concentrations of bromide than vertical wells. Another major difference between vertical and horizontal well concentrations is sulfate, which tends to be found at lower concentrations in horizontal wells. This might be the result of stronger reducing conditions in these formations. Reducing conditions can directly affect the solubility of redox-sensitive elements, such as iron, and indirectly affect the solubility of elements that are limited by the presence of sulfate, such as barium. A better understanding of such relationships may provide a means to gauge the representativeness of available data and fill remaining data gaps. If constituent relationships are based on geochemistry, rather than the unique properties of individual formations or well types, then the relationship should not be isolated to a single formation or well type. Therefore, EPA initially drew data from all well types (e.g., oil, coal bed methane, geothermal) to identify potential relationships. The most common relationship reported in the literature is between TDS and alkaline earth metals (e.g., barium, strontium). Because of the constant valence (+2), these elements do not sorb as strongly to silicate surfaces as monovalent ions. Therefore, as the overall ionic strength of groundwater increases, competition for binding sites could force barium and strontium into solution (IAEA, 1990, 2014; Sturicho et al., 2001). EPA compared available data for halides and alkaline earth metals to identify potential relationships. Chloride was selected as a proxy for TDS in this comparison because it is one of the most commonly reported analytes in produced water, is often the single largest contributors to TDS, and it eliminates double counting of barium and strontium included in the TDS measurement. While chloride may not directly compete with barium and strontium for binding sites, it provides a useful proxy for a range of cations that can. There is potential for chloride precipitation to weaken any relationship at the highest concentrations, though any relationships should still be apparent at lower concentrations. Although other ions, such as bromine, are less likely to precipitate, the relative lack of data for these ions can limit the conclusions that can be drawn from the comparisons. Figure 5-5 presents the best-fit relationships between chloride and both barium (n = 3,540) and strontium (n = 4,927). All relationships are graphed on a log scale. The red lines reflect the best-fit curves, while the black lines represent the corresponding standard deviation. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-21 Figure 5-5: Relationships of Chloride with Barium and Strontium. There is an apparent relationship between salinity and concentrations of both barium and strontium, though it is stronger for strontium. These relationships exist despite compounding sources of variability and uncertainty associated with data from different formations, well types, sample dates and analytical methods. EPA considered whether the strength of the relationships could be unduly influenced by extreme values. However, the available data are spread evenly over the reported interval and removal of individual studies, well types and statistical outliers did not diminish the overall relationship. Based on these findings, EPA reviewed the remaining dataset for other constituents that exhibit a relationship with salinity. Of the constituents with sufficient data for comparison, only lithium showed a similarly strong relationship (R2 = 0.78). Lithium is a monovalent cation of the same elemental group as potassium and sodium. The presence of high concentrations of other alkali metals may result in competition that forces more lithium into solution, similar to barium and strontium. Although salinity may influence the solubility of these constituents, it is clearly not the only factor. The standard deviation around each best-fit curve spans at least an order of magnitude. Other factors such as pH and dissolved oxygen might account for some of the remaining variability, though the relative importance of these other factors may change, depending on whether salinity dominates the water chemistry. EPA reviewed the literature to identify any other relationships that might exist and that could be evaluated with available data. The only relationships identified for barium and strontium were with bicarbonate and sulfate (Engle and Rowan, 2014). The authors noted that barium concentrations tend to be higher in sulfate-poor areas, while strontium concentrations tend be higher in bicarbonate-poor areas. An inverse relationship is present because bicarbonate and sulfate react with barium and strontium to form insoluble minerals that precipitate out of solution. EPA conducted a direct comparison of barium and strontium as a function of bicarbonate and sulfate, but found no apparent relationships. To understand the reason for the lack of a direct relationship, EPA considered the fact that salinity is also an important factor in barium and strontium solubility. It is possible the abundance of other ions in saline groundwater may limit the rate of chemical reactions, resulting in greater retention of barium and strontium in solution. Therefore, EPA conducted an Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-22 alternate comparison with both bicarbonate and sulfate expressed as a percentage of TDS. Figure 5-6 presents the best-fit relationships between bicarbonate and barium (n = 1,120) strontium (n = 1,659) and between sulfate and barium (n = 2,595) and strontium (n = 3,689). All relationships are graphed on a log scale. The red lines reflect the best-fit curves, while the black lines represent the corresponding standard deviation. Figure 5-6: Relationship of Bicarbonate and Sulfate with Barium and Strontium. As expected, bicarbonate and sulfate (as a percent of TDS) have an inverse relationship with barium and strontium. The strongest of these relationships are between barium and sulfate, which precipitate as barite (BaSO4), and between strontium and bicarbonate, which precipitate as strontianite (SrCO3). However, the same general trends are present for every combination. Differences in the strength of the relationships are likely because formation of barite and strontianite is more thermodynamically favorable and so exert greater control on dissolved concentrations. Barite has a lower solubility limit than celestite (SrSO4), which can result in faster precipitation of barium in high-sulfate waters (Zhang et al., 2014). EPA reviewed the remaining dataset for any other constituents that exhibit a relationship with either bicarbonate or sulfate. Of the constituents with sufficient data for comparison, none were found to have a similarly strong relationship. To better understand the combined impacts of bicarbonate, chloride and sulfate on barium and strontium, EPA conducted a multivariate regression analysis. For barium, the combination of chloride Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-23 and sulfate was statistically significant and resulted in an R2 = 0.81, which is a better fit than chloride (R2 = 0.64) or sulfate (R2 = 0.74) alone. For strontium, the combination of chloride, bicarbonate and sulfate was statistically significant and resulted in an R2 = 0.86, which is a better fit than bicarbonate (R2 = 0.73) alone, but is comparable to chloride (R2 = 0.86). EPA used the equation generated from this analysis to probabilistically predict barium concentrations based on chloride and sulfate. Because far more data are available for these major ions, this approach can provide a comparison for measured barium data to gauge the representativeness of the available data. For each paired sample of chloride and sulfate, a barium concentration was calculated based on the best-fit equation and then allowed to vary based on the standard deviation. This process was repeated 100,000 times to ensure convergence of the results. The resulting dataset was sampled probabilistically with data from each region weighted based on the relative volumes of natural gas and crude oil produced in each state (U.S. DOE, 2018c,d). All data from a given region was weighted equally in the distribution. Table 5-11 presents a comparison of barium from vertical wells based on empirical and modeled data. The comparison is limited to vertical wells because there are far fewer samples with paired chloride and sulfate compared to barium for horizontal wells, which introduces uncertainty into the comparison. Table 5-11. Comparison of Measured and Modeled Barium Concentrations (mg/L) Constituent Vertical n 1,593 Measured 50th 90th 4.8 171 n 50th 34,702 3.0 Modeled 90th 20 n = Number of Samples Measured/Modeled There is general agreement between the median values of modeled and measured concentrations, though there is a substantial difference between high-end values. This may indicate that the measured data overestimate barium concentrations on a national-scale. Samples measured for both barium and sulfate tend to have lower sulfate concentrations than the larger dataset that allow more barium to remain in solution. It could also indicate that modeled concentrations underestimate concentrations to some degree. Precipitation of halide and other minerals within the formation places an artificial ceiling on modeled barium concentrations. Therefore, EPA concludes that the measured and modeled data can provide reasonable bounds on the potential barium concentrations in produced water. Future data collection and analysis can further refine this relationship and improve predictions. Organic Compounds EPA identified several studies that analyzed organics in produced water from vertical and horizontal wells. A summary of data collection efforts is provided in Appendix B (Constituent Database). The full dataset for organic compounds was sampled probabilistically with data from each region weighted based on the relative volumes of natural gas and crude oil produced in each state (U.S. DOE, 2018c,d), the same as previously described for inorganic elements. All data from a given region were weighted equally in each distribution. The only compound with sufficient data to calculate summary statistics is benzene. The only well type with sufficient data are vertical wells. Table 5-12 presents the 50th and 90th percentile of the available data for benzene in produced water from vertical wells. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-24 Table 5-12. Organic Compounds in Produced Water (mg/L) Constituent Benzene Vertical n 50th 90th 27 / 32 0.23 4.9 n = Number of Samples Detected / Total Although the most data are available for benzene, there are many other organic compounds that have been identified in produced water. As many as 1,400 to 2,500 compounds have been tentatively reported based on chromatogram energy peaks, though less than half this amount have been identified with confidence (Hoelzer et al., 2016; Khan et al. 2016). Many of these may be isomers, acids, substitutions and other variations of previously identified compounds. EPA identified eleven studies that analyzed for organics in produced water.12 However, some of these studies only report whether a compound was detected and not the associated concentrations. These studies analyzed samples drawn from several unnamed conventional formations, as well as the Marcellus, Eagle Ford and Barnett shales. The 1987 Technical Support Document (U.S. EPA, 1987d) analyzed a total of 444 organic compounds in produced water from vertical wells that included a range of volatile (n = 55), semi-volatile (n = 176), dioxin and dioxin-like compounds (n = 136) and pesticides (n = 77). Many of the compounds were below detection limits in all samples. The types of compounds detected most frequently include aliphatic hydrocarbons (i.e., C12 – 30), ketones (i.e., methyl isobutyl ketone, isophorone), alcohols (i.e., terpineol), phthalates [i.e., bis(2-ethylhexyl) phthalate], simple aromatic hydrocarbons (i.e., benzene, ethylbenzene, phenol and methylated substitutions, toluene), polycyclic aromatic hydrocarbons [i.e., 2-(methylthio)benzothiazole, dibenzothiophene, naphthalene and methylated substitutions] and other volatile organics (i.e., carbon disulfide). The compounds measured at the highest concentrations tended to be aliphatic and simple aromatic hydrocarbons, which are common components of crude oil. A concurrent study conducted by the American Petroleum Institute identified similar concentrations of many constituents (API, 1987). Many of the same compounds reported in U.S. EPA (1987d) were also detected in more recent samples from vertical wells (MSC, 2009; Maguire-Boyle and Barron; 2014; Orem et al., 2014; Ziemkiewicz and He, 2015; Khan et al., 2016). These studies reported several additional compounds measured for, but not detected, in the 1987 studies. Examples include phthalates (e.g., di-n-octyl-phthalate), simple aromatic hydrocarbons (e.g., benzyl alcohol), polycyclic aromatic hydrocarbons (e.g., fluorene, phenanthrene, pyrene, pyridine) and other volatile compounds (e.g., bromoform, chloroform). Concentrations of these additional constituents were generally low and may be the result of improved detection limits. It is also possible that some of these compounds were added to injected water as a solvent, biocide, lubricant, tracer or other purpose. The attribution of compounds is complicated by uneven reporting of usage and the fact that some compounds added to injected water are the same as those that occur naturally in the formation. For example, naphthalene was reported in 19% of FracFocus 1.0 disclosures (U.S. EPA, 2016a). The practice of recycling produced water as the base fluid for hydraulic fracturing can also introduce naturally-occurring organics into the fluid. Furthermore, 12) API, 1987; U.S. EPA, 1987; Hayes, 2009; Maguire-Boyle and Barron; 2014; Orem et al., 2014; Abualfraj et al., 2014; Ziemkiewicz and He, 2015; Hoelzer et al., 2016; Khan et al., 2016, U.S. EPA, 2016c; USGS, 2016 Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-25 the high temperature, pressure and salinity found in many hydrocarbon formations has the potential to transform the compounds through processes such as methylation and halogenation (Hoelzer et al., 2016). MSC (2009), Orem et al. (2014) and Ziemkiewicz and He (2015) reported concentrations of organic compounds in the water at different stages of production. Compounds detected in water used as a base for hydraulic fracturing fluid include acetone, bromoform, naphthalene, trimethylbenzene and xylene. This indicates that the base is recycled produced water and so it is not clear if the detected compounds originate from the formation or additives. Compounds that were detected in the prepared fracturing fluid and that decreased over the first 20 days of production include bis(2-chloroethyl)ether, carbon disulfide and methylnaphthalene. The lack of contribution from the formation indicates that these compounds originate primarily from additives. Although 20 days is a relatively short timeframe relative to the lifespan of a well, it is also typically when the largest volumes of produced water are generated (U.S. EPA, 2016a). Therefore, the presence of these organic compounds may still be environmentally significant. The organic compounds reported in produced water vary widely in solubility and hydrophobicity. Although potential health effect endpoints have been identified for some compounds, toxicity values have not yet been developed for many, particularly the various derivatives and degradation products (U.S. EPA, 2016a). Therefore, it is difficult to quantify the magnitude of potential risks associated with releases of these compounds to the environment. Radioisotopes EPA identified several sources that analyzed for radioisotopes in produced water from both vertical and horizontal wells. A summary of the data collection efforts is provided in Appendix B (Constituent Database). The full dataset for radioisotopes was sampled probabilistically with data from each region weighted based on the relative volumes of natural gas and crude oil produced in each state (U.S. DOE, 2018c,d), the same as previously described for inorganic elements. All data from a given region were weighted equally in each distribution. The only isotope with sufficient data for summary statistics was 226Ra. Table 5-13 presents the 50th and 90th percentile of the available data for 226Ra in produced water from vertical and horizontal wells. EPA also considered how reported sample errors could affect summary statistics, but the addition of error measurements to reported activities had negligible impact on the calculated summary statistics. Therefore, EPA only summarized reported activities in this table. Table 5-13. Radioisotopes in Produced Water (pCi/L) Constituent Radium-226 n 127 / 127 Vertical 50th 145 90th n Horizontal 50th 1,060 69 / 69 2,300 90th 4,470 n = Number of Samples Detected / Total This comparison indicates that both high-end and median activities of 226Ra are higher in horizontal wells. These differences mirror those observed for barium and strontium. Radium is also an alkaline earth metal and so similar behavior is expected. Multiple studies have reported relationships between salinity and radium, but noted that the slope of the relationship can vary among formations (ILGS, Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-26 1983; Chermak and Schreiber, 2014). This aligns with previous findings that salinity is not the sole factor that influences barium and strontium solubility. EPA considered both chloride and bromide in the comparison due to similar amounts of paired data available. Figure 5-7 presents the relationships for 226Ra with chloride (n = 459) and bromide (n = 242). All relationships are graphed on a log scale. The red lines reflect the best-fit curves, while the black lines represent the corresponding standard deviation. Figure 5-7: Relationship of Chloride and Bromide with Radium-226. There is a clear relationship between salinity and radium activity. Both chloride and bromide provide a good fit. Although bromide provides a slightly better fit, this may be influenced by fewer data points clustered closer to the highest and lowest values. EPA also compared radium activity with bicarbonate and sulfate (as a percent of TDS), but did not identify any similarly strong relationships. This may be because the range of radium concentrations reported in literature all fall below the solubility limit of radium minerals, such as radium sulfate (Sturchio et al., 2001; SKB, 2008). The highest reported activity of 27,000 pCi/L corresponds to a dissolved concentration of only 0.027 μg/L. Instead, radium loss is driven primarily by co-precipitation with barium and strontium, which are part of the same group of alkaline earth metals (Zhang et al., 2014). It is possible that a relationship with bicarbonate and/or sulfate does exist; weak inverse trends can be seen in plotted data. Yet such an indirect relationship would be more complex than those identified for barium or strontium and may require other types of data or different handling of existing data to identify. The majority of available studies sampled only for 226Ra because the longer half-life of this isotope makes it more persistent in the environment. Omission of 228Ra can substantially underestimate total radium activity in samples, which can result in an underestimation of risk and may skew relationships present in the data. Therefore, EPA explored both whether it is possible to predict 228Ra activity based on measured 226Ra activity and how inclusion of both isotopes may affect the relationship with salinity. The available literature is inconsistent on whether a relationship exists between radium isotopes. Some studies report a strong correlation between the two isotopes (Fisher, 1998), while others found a more moderate relationship (U.S. DOE, 2004) or none at all (ILGS, 1983). Figure 5-8 presents the relationship between 226Ra and 228Ra (n = 120) and between chloride and 226+228Ra (n = 120). All relationships are Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-27 graphed on a log scale. The red line represents the best-fit curve, while the black lines represent the corresponding standard deviation. Figure 5-8: Relationships of Radium-226 and Radium-228. This left graph shows a strong relationship between the activities of different radium isotopes. This is reasonable, given that all isotopes of radium will behave the same chemically. Anything that increases the solubility of 226Ra should have a similar effect for 228Ra. However, as 226Ra activity increases, 228Ra tends to decrease as a fraction of the total radium. Some studies have reported that the ratio of radium in produced water mirrors that of the parent rock (Sturicho et al., 2001). The decreasing radium ratio may reflect the greater potential for uranium to accumulate in the high-organic rock in hydrocarbonbearing formations. The best-fit equation indicates that the average 228Ra/226Ra ratio will range between 0.3 and 0.4, based on the 50th and 90th percentile of measured 226Ra activity. This compares well with previous estimates around 0.3 (U.S. EPA, 1993; Bernhardt et al., 1996). Inclusion of both isotopes shown in the right graph results in a noticeable shift in the best-fit line toward higher activities (e.g., 230 vs 98 pCi/L at 10,000 mg/L Cl). The addition of radium isotopes also results in a better fit though, again, this may be influenced by fewer data points clustered closer to the highest and lowest values. To better understand the impact of chloride and bromide on dissolved 226Ra activity, EPA conducted a multivariate regression analysis. This analysis was only conducted for 226Ra because it is the only isotope with sufficient measured data to allow a comparison. EPA used the equation generated from the regression analyses to probabilistically predict 226Ra activity based on measured chloride and bromide concentrations. For each sample of chloride or bromide, a radium activity was calculated based on the best-fit equation and then allowed to vary based on the standard deviation. This process was repeated a total of 100,000 times to ensure convergence of the results. The resulting dataset was then sampled probabilistically with data from each region weighted based on the relative volumes of natural gas and crude oil produced in each state (U.S. DOE, 2018c,d). Data from a given region were weighted equally in each distribution. Table 5-14 presents a comparison of activities from empirical and modeled data. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-28 Table 5-14. Comparison of Measured and Modeled Radium-226 Activities (pCi/L) Constituent Vertical Horizontal n 127 69 Sampled 50th 90th n Modeled (Cl) 50th 90th 145 2,300 1,060 4,470 39,766 291 187 341 565 587 n 4,057 186 Modeled (Br) 50th 145 1,095 90th 867 2,397 n = Number of Samples Measured/Modeled There is overlap among the three datasets, though chloride and bromide both predict lower activities than reported in the literature. This could be because many studies tend to focus on individual wells or formations already known to have elevated radioactivity, which can skew the dataset higher. Predictions with chloride result in the lowest activities, similar to barium. Precipitation of halide and other minerals within the formation could place an artificial ceiling on modeled radium activities. Despite these uncertainties, the predicted activities generally agree with the overall magnitude of activities reported in the literature. Therefore, EPA concludes that the combination of measured and modeled data can provide reasonable bounds on estimates of potential radioactivity in produced water. Future data collection and analysis can further refine these relationships and improve predictions. 5.3.2. Volatile Emissions The presence of volatile organic compounds (e.g., benzene) and radioisotopes (e.g., radon) indicate there is potential for releases to the surrounding air. However, EPA did not identify any sources that analyzed for volatile emissions of organic or inorganic constituents from produced water. Therefore, no conclusions can be drawn about the magnitude or frequency of these releases. 5.3.3. Summary – Produced Water Based on the available data, EPA concludes that similar concentrations of some inorganics and radionuclides are possible in produced water generated from vertical and horizontal wells. As a result, the magnitude of releases to the environment or deposition to downgradient wastes (e.g., scale and production sludge) can be similar. The extent to which constituent concentrations in produced water are related to the permeability of the formation is not clear at this time because the available literature often does not provide this information about the sampled formations. However, the relationships identified from the literature indicate local geochemistry is more important than the specific well type in determining the magnitude of dissolved concentrations in the produced water. The relationships identified from the literature cannot be used to predict the exact concentration in the produced water from any individual well. There are too many remaining sources of variability that result in a range of potential concentrations that extend an order-of-magnitude or more. However, these relationships may provide probabilistic distributions that can be used to predict likely concentrations in an area. Further investigation can refine known relationships and may also identify additional ones. It is clear that there are also numerous organic compounds that may be present in produced water. However, insufficient data are available to compare these organic concentrations from vertical and horizontal wells. The most commonly detected organic compounds are commonly associated with hydrocarbons (e.g., benzene, toluene), but these compounds do not always originate from the Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-29 formation. Source attribution is complicated by inconsistent reporting on additive usage in hydraulic fracturing fluids, chemical transformation within the subsurface, and the increasing practice of recycling produced water back into hydraulic fracturing fluid. Even when the structures of the organic compounds present are known, there may not yet be data on the potential mobility and toxicity. Without these data, the potential risks associated with releases to the environment cannot be quantitatively evaluated. Pipe Scale Pipe scale is the hard precipitate that accumulates on the walls of pipes and other equipment. There are multiple types of scale that can form, which depend on the minerals that are at or near saturation in the produced water. The scale that forms can occur as a single compound or as an amalgamation of similar compounds. The most common types of scale are carbonates (e.g., CaCO3), halides (e.g., NaCl), silicates (e.g., Fe2SiO4), sulfates (e.g., SrSO4) and sulfides (eg., PbS). Sulfate scale is the dominant type associated with oil and gas wells. There are two main causes of sulfate scale. The first is mixing of incompatible waters. When water injected into the well to enhance recovery has high sulfate levels relative to the formation water, then scale may precipitate instantaneously and in high volume. In extreme cases, this type of scale formation has completely clogged wells in under a day (Crabtree et al., 1998). The other cause is changes in mineral solubility as a result of the decreasing pressure and temperature of water as it is brought to the surface. Generally, minerals are about half as soluble at 77 °F (25 °C) than at 203 °F (95 °C), and about half as soluble at atmospheric pressure than at 7,000 psi (48 MPa), regardless of the initial concentration (Oddo and Thomson, 1994; Crabtree et al., 1998). This type of accumulation of scale can be gradual and might not be detected until the equipment is taken out of commission (Collins, 1975; Kan and Tomson, 2010). Sulfate scale that forms on equipment surfaces is highly resistant to removal through either mechanical or chemical means. Scale inhibitors can be mixed in the injected water to reduce or eliminate scale formation either by increasing the solubility of the compound or by disrupting the ability of the scale to affix or grow on equipment surfaces (Crabtree et al., 1998). These additives can eliminate scale formation when the water is slightly oversaturated, but it may not be possible to entirely prevent scale formation when water is highly oversaturated (Kan and Tomson, 2010). Some of the scale may instead precipitate out as independent minerals or onto suspended solids before settling out of solution further down the production stream. The remainder of this section focuses on scale that forms as relatively homogenous deposits on equipment surfaces. Scale deposited in sludge further along the production stream is discussed in a subsequent section of this document. 5.4.1. Bulk Content Common types of sulfate scale associated with oil and gas wells are anhydrite (CaSO4), barite (BaSO4) and celestite (SrSO4). The amount of each that precipitates depends on the relative concentrations and solubility of these minerals in the produced water. Due to the extremely low solubility of barite, it is often the dominant mineral (Crabtree et al., 1998; Zhang et al., 2014). Scale samples collected from Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-30 Texas had an average composition of 31% Fe, 14% Ba, 2% Sr and 1% Ca (TXBEG, 1995).13 Scale samples from Brazil had an average composition of 40% BaO, 9% SrO and only 3% FeO (Godoy and Petinatti da Cruz, 2003).14 Radium does not form an independent mineral phase because dissolved concentrations are orders-ofmagnitude below saturation, even at the highest measured activities (Sturchio et al., 2001; SKB, 2008). However, radium will readily co-precipitate with barite by substituting for barium in the crystal lattice (Zhang et al., 2014). As a result, radium can precipitate regardless of the amount dissolved in water. A review of the literature indicates that radium is the primary constituent of concern associated with this waste stream. Table 5-15 presents a summary of radium content in pipe scale from different states. EPA identified thirteen studies that provide data from nine states. EPA did not identify any data of the volume of scale generated in these or other states. As a result of this and differences in both sample size and reported activities among the studies, EPA did not attempt to further aggregate the data. Table 5-15. Radioisotopes in Scale (pCi/g) State Well Type Ra226 n 50th Ra228 90th n 50th 90th 501 California Vertical 22 / 22 9.3 512 22 / 22 15 Kentucky Vertical 13 / 13 1,711 2,164 10 / 10 45 Louisiana Vertical 9/9 360 1,226 1/1 Michigan Vertical 11 / 12 539 1,466 11 / 12 60 New York Vertical 7/7 1.0 5.2 4/6 0.60 2.5 Horizontal 38 / 40 148 1,434 38 / 40 76 599 Oklahoma Vertical 8/8 1,715 1,851 1/8 0.05 4.0 Pennsylvania Vertical 2/2 2.0 2.6 2/2 1.2 1.3 Texas Vertical 37 / 37 895 2,436 37 / 37 1,295 3,880 North Dakota 55 120 111 n = Number of Samples Detected / Total Both high-end and median scale activity are elevated in multiple states. Most studies reported instances of combined radium activities far greater than the upper bound of 4.2 pCi/g measured in surface soil (U.S. DOE, 1981a). Thus, there is clear potential for high activities in this waste. However, it is not possible to define a representative distribution of potential activities with available data because of the approach used to select sample locations. Some studies conducted an initial survey of operating equipment with hand-held instruments to guide sample collection toward areas of elevated activity. This preferential sampling of hotspots is likely to overestimate the prevalence of higher activities. A survey overseen by API concluded that between 10 and 30% of oil and gas wells in the United States produce radium-enriched scale in pipes and other equipment (API, 1989; Rood et al. 1998). However, the basis for that estimate is measurements taken around the external surface of the equipment. As a result, this estimate does not account for downhole accumulations that may occur over time. Furthermore, measurements on the external surface of equipment may underestimate the magnitude of radioactivity present due to shielding of gamma radiation. Based on the work of Bernhardt et al. 13) If all Ba and Sr are present as sulfates, these minerals would account for 25% and 4% of the total mass, respectively. 14) If all Ba and Sr are present as sulfates, these minerals would account for 60% and 15% of the total mass, respectively. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-31 (1996), a steel pipe with internal activity as high as 60 pCi/g 226Ra could result in external measurements comparable to background.15 However, greater exposures are possible when the scale is disturbed during management and disposal. Although relatively low activities were reported for New York and Pennsylvania, the same studies measured produced water activities above 1,000 pCi/L 226Ra. Therefore, there is ample radium available to precipitate if conditions are favorable. The measured concentrations of barium and sulfate are similar to those in states with higher scale activity and overlap with solubility limits modeled under standard environmental conditions (Langmuir and Melchior, 1985; SKB, 2008). This indicates that radium may precipitate gradually over time. It is possible that the small number of samples reported by these studies missed areas of higher activity. Recent studies have reported favorable conditions for scale formation from the horizontal wells in these states (Blauch et al., 2009; Engle and Rowan, 2014). Many of the studies reported activities for both 228Ra and 226Ra in scale. The isotope ratio of 228Ra/226Ra in freshly deposited scale should mirror that of the produced water because different isotopes of the same element exhibit the same chemical behavior. However, the isotope ratio of scale will decrease over time. The shorter half-life of 228Ra (i.e., 5.7 years) compared to 226Ra (i.e., 1,600 years) results in the depletion of 228Ra in older samples (Fisher and Hammond, 1994). Few studies reported the age of scale samples. In cases of gradual accumulation, it is often unknown how long scale is present in a pipe before it is removed from service and how long after that the samples have been stored in pipe yards or drums awaiting disposal. One study that measured 214Pb and 214Bi found these radioisotopes to be in approximate equilibrium with 226Ra, but found 210Pb was a factor of four lower (Landsberger et al., 2016). If decay of 226Ra were the only source of 210Pb (i.e., no independent precipitation), the age of this scale would be at least 10 years old. Another study estimated the age of scale found in a pipe yard to be nearly 30 years old (Zielinski et al., 2000). This is another source of uncertainty when defining representative activities at the time of disposal. 5.4.2. Leachate EPA identified few studies that evaluated the leaching behavior of scale from oil and gas wells. Studies of similar scale from uranium mine tailings reported barite to be insoluble under typical environmental conditions, but more soluble under reducing conditions (Fedorak et al., 1986; Huck and Anderson, 1982; Huck et al., 1989; McCready et al., 1980). Chemical reduction of sulfate is often a slow process, but biologically-mediated reduction can occur at a much faster pace when conditions are favorable. Bacteria capable of reducing sulfates occur naturally in the soil, though the high concentrations of inorganic elements and organic compounds in produced water might inhibit bacterial growth (Phillips et al., 2001; U.S. DOE, 2004). As a result, the two available studies of oilfield scale focused on samples that had been incubated with soil or bacterial cultures to enhance releases. Phillips et al. (2001) incubated a scale sample of 1,300 pCi/g 226Ra with and without bacteria isolated from production pit for ten months. The presence of sulfate-reducing bacteria increased the dissolved activity from 0.54 to 15) 60 pCi/g results in an estimated exposure rate around 7 microroentgens (μR)/hr. API (1989) reported median background exposure rates across the United States ranging from 5 to 9 μR/hr. MIDNR/DPH (1991) reported background rates in Michigan between 3 and 7 μR/hr, while U.S. DOI (1997b) reported rates in Kentucky between 7 and 8 μR/hr. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-32 14.9 pCi/L 226Ra. DOE (2004) incubated scale samples with soil collected from the sample area for two weeks. However, this study reported the leachate activity as a percentage of the original bulk activity. Without additional information on both the bulk activity of the sample and the liquid-to-solid ratio of the leaching test, these data cannot be converted to a comparable dissolved activity. Discussion solely in percentages can also give the misleading impression that the leachate activity is low. For example, the activity reported by Phillips et al. (2001) was equal to only 0.04% of the total mass. Neither of the studies reported the final pH of the leachate. Therefore, there is uncertainty about the environmental conditions these samples reflect. This uncertainty may be minor, as geochemical modeling indicates that leaching from scale is independent of pH outside of extremely acidic (pH < 2) or basic (pH > 12) conditions (Huck et al., 1989). Yet shifts in pH could also inhibit the growth of bacteria that drive barite reduction. In addition, there are no data available on how leaching from the scale might change over time. Because the bacteria break down a fundamental component of the scale matrix as a source of energy, it may be reasonable to assume a substantial fraction of the radium could eventually be released. Another source of uncertainty in the available data are that neither study measured releases of both Ra and 228Ra from scale. Therefore, both studies underestimate the magnitude of radium leached to some degree. Phillips et al. (2001) reported the activity of both isotopes in the scale sample, but only the leached 226Ra activity. Under the assumption that the two isotopes are equally distributed in the scale matrix and thus have a similar potential to leach, total activity in the presence of sulfate-reducing bacteria would fall closer to 27.2 pCi/L 226+228Ra. 226 5.4.3. Air Emissions Radon is the only member of the uranium and thorium decay chains that exists as a gas at room temperature. Two isotopes of radon, 222Rn and 220Rn, are created by the direct decay of 226Ra and 228Ra, respectively. The majority of studies do not analyze for 220Rn because the much shorter half-life (i.e., 55 seconds) limits potential exposures, particularly when the gas must first migrate through soil or other porous media. Even for the longer lived 222Rn (i.e., 3.8 days), some fraction of the gas will not escape into the atmosphere. Therefore, releases are frequently reported in terms of the relative amount of radon that does escape (i.e., emanation fraction). There is no correlation between the activity of this waste and the emanation fraction. Releases are controlled by the physical structure of the waste, rather than the overall activity, so these measurements can be used together with the activity in other samples to estimate potential emission rates. EPA identified two studies that analyzed samples collected from Kentucky, Louisiana, Michigan, Oklahoma and Texas (Wilson and Scott, 1992; U.S. DOE, 1999b). Because the emanation fraction is not a function of activity, EPA combined data from the different states. The data are instead broken out based on the integrity of the scale samples. Some studies have reported substantial differences between the larger samples of intact scale still attached to the pipe and the smaller disturbed samples collected from the ground and drums. Table 5-16 presents the 50th and 90th percentile of the available data for radon emanation from intact and disturbed pipe scale. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-33 Table 5-16. Radon Emanation Fraction from Scale Isotope Emanation Fraction n 50th 90th Intact Scale 31 / 31 0.039 0.095 Disturbed Scale 18 / 18 0.135 0.239 n = Number of Samples Detected / Total As reported in the literature, available data show that samples of disturbed scale tend to have higher emanation fractions. Because emanation is limited by the rate at which radon can migrate out of the scale, it is reasonable that scale with a higher surface area to volume ratio would also have higher relative emanation (U.S. DOE, 1999b; White and Rood, 2000; Phillips et al., 2001). The density of intact barite deposits on equipment is estimated to be around 2.6 g/cm3, which is comparable to that of many rocks (U.S. DOE, 1996). The emanation fraction of this intact scale is comparable to undisturbed soil (Rood et al., 1998). In contrast, disturbed scale has emanation fractions comparable to uranium mine tailings (White and Rood, 2000). There is little overlap in the data for these two types of samples. Therefore, use of lower emanation fractions to estimate releases from scale that is separated from the pipe or otherwise disturbed during disposal is likely to underestimate potential exposures. 5.4.4. Summary – Pipe Scale Available data show that pipe scale can form on oil and gas equipment in any region of the country. Radium activities in measured and modeled produced water from both vertical and horizontal wells are high enough to cause the activities measured in pipe scale. However, high dissolved radium activity alone does not guarantee that high-activity scale will form. Radium typically precipitates along with sulfate or carbonate minerals, so the rate and extent of precipitation depends on the chemistry of the formation. When scale forms on equipment surfaces, it may accumulate slowly and not be apparent until after the equipment has been taken out of service. Use of scale inhibitors can reduce the total volume that adheres on the equipment surfaces over time, but inhibitors may not completely prevent scale formation. If inhibitors only delay deposition, then greater radium accumulation may occur in downgradient wastes, such as production sludge. Pipe scale is anticipated to be managed independently from other wastes because of the considerable effort required to physically or chemically dislodge the scale from equipment surfaces. However, the Agency identified little documentation on where pipe scale is currently disposed. The radium activities reported in the literature would pose additional management challenges, as the activities are frequently higher than the limits allowed in many landfills. It is important to note that the available data may be biased toward higher activities because some studies used hand-held instruments to guide sample collection toward areas of elevated activity. As a result, a greater fraction of the scale generated may have lower activities than predicted by the current dataset. However, remaining scale may also have elevated activities that are shielded from surface measurement by the metallic equipment. This represents a major source of uncertainty in the current data. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-34 Production Sludge Production sludge (hereafter referred to simply as “sludge”) is a mixture of the solid and fluid residues (e.g., heavy hydrocarbons, formation solids, chemical precipitate) that collect in equipment and other vessels along the production stream. Sludge is typically found as a loose material and may also be referred to as sediment, bottoms or settlings. One study reported that the highest rate of sludge accumulation occurs in storage tanks (API, 1989), which may result from longer residence times. Yet, even there, accumulation can be a gradual process. Deposition rates have been reported between 1 and 4 cm/yr per well (U.S. EPA, 1993; Zielinski and Budahn 2007). Depending on the dimensions of an individual pit or tank, disposal of the accumulated sludge might not occur until years after the start of production. 5.5.1. Bulk Content The composition of sludge is partly dependent on the characteristics of the produced water, though silica and barium compounds are often the primary minerals present (U.S. EPA, 2000a). Samples collected around the coast of Louisiana had an average solids composition of 50% SiO2 and 20% BaSO4 (Fisher and Hammond, 1994). Samples collected from Brazil had an average solid composition of 35% SiO2 and 12% BaO (Godoy and Petinatti da Cruz, 2003).16 Both studies also reported more minor contributions from aluminum, calcium and iron oxides. The barite in sludge is similar to that found in scale, but there are currently no practical means to separate this mineral from the remaining sludge due to the small size and brittleness of the precipitate (Fisher and Hammond, 1994; U.S. DOE, 2004). Therefore, the barite is considered to be a fundamental component of the sludge, rather than a mixture of separate wastes. Inorganic Elements EPA identified seven studies that measured inorganic elements in sludge. EPA separated the available data into two sets for comparison based on the analytical methods used in the studies. This is because of substantial differences identified between samples of drilling solids that had been analyzed with acid digestion methods and non-destructive methods. Four studies used digestion methods on samples from at least four states (API, 1987; U.S. EPA, 1987, 2000; Zielinski and Budhan, 2007). Three studies used non-destructive methods on samples collected primarily from one state, with additional samples from two others (Fisher and Hammond, 1994; Landsberger et al, 2012; Zhang et al., 2015). The majority of these data were drawn from vertical wells. The limited data available for horizontal wells fell within the range reported for vertical wells and so EPA combined the data from both types of wells for this comparison. Table 5-17 presents the 50th and 90th percentile of the available data for inorganic elements in sludge detected in at least half of one of the datasets. 16) If all of the measured BaO is present as BaSO4 then this would account for closer to 18% of the total mass, similar to samples collected from around the Gulf of Mexico. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-35 Table 5-17. Inorganic Elements in Sludge (mg/kg) Constituent Acid Digestion Non-Destructive n 50th 90th n 50th Antimony 0/0 -- -- 15 / 17 27 54 Aluminum 9/9 1,500 16,221 2/2 46,500 50,100 Arsenic 6/7 3.3 4.3 17 / 17 64 436 Boron 8/8 34 143 0/0 -- -- Barium 9/9 1,340 8,735 21 / 21 101,000 231,000 Chromium 90th 59 / 59 18 27 0/0 -- -- Cobalt 3/5 2.8 19 17 / 17 35 77 Copper 60 / 60 18 43 17 / 17 292 720 Iron 9/9 5,700 37,807 2/2 59,250 66,650 Lead 5/6 69 151 17 / 17 872 7,620 Manganese 9/9 72 578 0/0 -- -- Molybdenum 2/5 0.25 9.9 10 / 17 5.0 51 127 Nickel 49 / 59 16 30 17 / 17 32 Selenium 1/7 1.0 2.4 13 / 17 10 42 Strontium 11 / 11 200 256 18 / 18 3,425 29,570 Vanadium 12 / 12 8.9 26 0/0 -- -- Zinc 67 / 67 59 159 19 / 19 1,170 11,560 n = Number of Samples Detected / Total Total concentrations are higher than acid-extractable concentrations for all constituents, regardless of where the samples were collected. Differences of an order of magnitude or more are too large to only be explained by regional variability. The more likely cause is that non-destructive analytical methods measure the full constituent mass within the sample matrix, while digestion methods measure the constituent mass that can be liberated from the matrix with a combination of heat and acid (Gaudino et al., 2007). If a fraction of the sludge is recalcitrant, it will not dissolve during acid digestion. This can result in an underestimation of the total concentration present in the waste. If the recalcitrant fraction will not be released from the sludge, it may not be appropriate to consider this additional mass in exposure estimates. However, studies have shown that reducing conditions can mobilize constituent mass from otherwise recalcitrant minerals, such as barite (Phillips et al. 2001; U.S. DOE, 2004). Therefore, it may still be appropriate to consider the total mass if the sludge is managed in a biologically-active, reducing environment. This is a major source of uncertainty in the current data. Organic Compounds EPA identified two studies that measured organic compounds in sludge (API, 1987; U.S. EPA, 1987). Samples were collected from vertical wells in at least three states. The uncertainties associated with measurement of inorganic elements are not anticipated to be as great a concern for organic compounds. Residual oil is typically present as a separate layer from other precipitate and so the mineral phase is less likely to interfere with laboratory analysis or to limit potential exposures. Therefore, given the relatively small number of samples available, EPA combined all available data into a single distribution. Table 4-18 presents the 50th and 90th percentile of the available data for organic compounds in sludge. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-36 Table 5-18. Organic Compounds in Sludge (mg/kg) Constituent Percentile n 50th 90th 7/8 63 218 Toluene 8/8 15 609 Ethylbenzene 9 / 10 21 307 Xylene 2/2 317 571 Benzene n = Number of Samples Detected / Total All of the data were collected around 1987, so there is some uncertainty whether these data reflect the sludge that is currently generated. In the absence of more recent sludge data, EPA considered data for produced water because it is one primary source of the organic compounds in sludge. Samples collected in the last decade have a similar range of benzene, toluene, ethylbenzene and xylene (BTEX) concentrations as those from the 1980’s. This indicates that current sludge has a similar potential to retain dissolved and emulsified organics from produced water. In addition, the equipment used to separate oil and water still relies on differences between the density of oil and water. This indicates that current sludge also has a similar potential to retain heavier hydrocarbons that settle out of the water. Based on these considerations, EPA concludes that available data can still provide useful information about the magnitude of potential concentrations. These data show that substantial enrichment of organic compounds in sludge is possible. However, the small number of total samples make it difficult to draw conclusions about the overall distribution of concentrations and how frequently higher concentrations will occur. Radioisotopes EPA identified thirteen studies that measured radioisotopes in sludge. The majority of these studies collected samples from vertical wells in eight states (MIDNR/MDPH, 1991; PADEP, 1992; CADHS/DC, 1996; Pardue and Guo, 1998; NYDEC, 1999; U.S. DOE, 1999a,b; U.S. EPA, 2000a; Zielinski and Budahn, 2007; Landsberger et al., 2012). Two studies collected samples from vertical wells in two states (U.S. DOE, 2014; Zhang et al., 2015). Radium is the most commonly measured radionuclide in sludge because it is the most highly concentrated in produced water and frequently co-precipitates with barium. As a result, this isotope is likely to be sequestered in the recalcitrant fraction of the sludge. However, the uncertainties associated with measurement of inorganic elements are not anticipated to be as great a concern for radioisotopes. Gamma radiation can easily pass through solid materials and so the mineral phase is less likely to interfere with laboratory analysis or to limit potential exposures. A number of radioisotopes may also be present in sludge from different sources, but the most data were available for radium because of the potential for high activities through barite precipitation. Given the variable amount of data available for each state and the substantial differences among the reported activities, EPA separated the data out by state. Table 5-19 presents the 50th and 90th percentile of the available data for radium in sludge. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-37 Table 5-19. Radioisotopes in Sludge (pCi/g) State Radium 226 Well Type Radium 228 n 50th 90th n 50th California Vertical 5/5 2.3 10 5/5 3.7 11 Louisiana Vertical 24 / 24 667 101,244 10 / 10 560 37,392 Michigan Vertical 3/3 436 4,654 3/3 220 1,470 New York Vertical 9/9 2.0 6.7 8/9 2.1 4.3 Horizontal 57 / 57 25 98 57 / 57 11 25 Vertical 9/9 25 / 25 53 1,072 7/9 4.6 28 Vertical 0.7 1.1 25 / 25 0.7 1.5 Horizontal 2/2 281 408 0/0 -- -- Vertical 29 / 29 124 760 29 / 29 44 187 North Dakota Oklahoma Pennsylvania Texas 90th n = Number of Samples Detected / Total Measured scale activity is variable among the states. Yet most studies report instances of 226Ra activities far greater than the upper bound of 4.2 pCi/g 226Ra measured in surface soil (U.S. DOE, 1981a). Thus, there is clear potential for elevated activities in this waste. However, it is not possible to define a representative distribution of potential activities with available data because of the approach used to select sample locations. Some studies conducted initial surveys of the pits and tanks with hand-held instruments to guide sample collection toward areas of elevated activity, which may overestimate the prevalence of higher activities. For example, some samples from Louisiana reported by Fisher and Hammond (1994) have activities nearly two orders of magnitude higher than those measured in other states. Such high activities are theoretically possible and have been reported in pipe scale, but are unlikely to be as common as data from this study might suggest. Other studies may underestimate potential activities due to the small number of samples reported. For example, samples from California reported by CADHS/DC (1996) have lower activities than most other states. However, the same study identified much higher activities in both produced water and scale, which makes it likely that higher activities can also occur in sludge. 5.5.2. Leachate The leachate data reported in the literature analyzed by TCLP (SW846 Method 1311). This single-point leaching test is intended to mimic acidic conditions that result from the decomposition of organic matter in a landfill. This scenario can result in high leachate concentrations both because the solubility of many constituents is highest at acidic pH and because strong acids can decompose mineral complexes that would otherwise hold the constituent mass in place (U.S. EPA, 2014c). As a result, these data have the potential to overestimate releases if wastes are managed under less extreme conditions. However, because this leachate test uses a fixed amount of buffer, wastes with high alkalinity may shift the final pH of the leachate closer to neutral. None of the available studies reported the final pH of the leachate. This is a major source of uncertainty for the available data because the solubility of some constituents can change dramatically over a small pH range. Thus, while available data provide useful information about the potential magnitude of releases, it is difficult to draw conclusions about potential releases. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-38 Inorganic Elements EPA identified four studies that measured inorganic elements in the leachate from sludge. These studies reported samples collected from at least five states, though the amount of data from each state is variable (API, 1987; U.S. EPA, 1987; 2000a; LADNR, 1999). LADNR (1999) and U.S. EPA (2000a) reported a considerable amount more data for one constituent (barium) than other studies collected from Louisiana and Pennsylvania, respectively. EPA did not identify information that could be used to further weight the data to obtain a more representative national distribution, such as the volume of waste generated in each state. Therefore, the data from each study was weighted equally. Table 5-20 presents the 50th and 90th percentile of the available data for inorganic elements in leachate from sludge detected in at least half of samples. Table 5-20. Inorganic Elements in TCLP Leachate from Sludge (mg/L) Constituent Aluminum Barium Boron Cobalt Iron Manganese Nickel Strontium Vanadium Vertical Well n 50th 90th 7/8 320 / 376 10 / 11 3/4 11 / 11 11 / 11 4/6 5/5 3/5 0.40 1.4 1.1 0.02 25 1.9 0.05 6.5 0.003 6.1 7.7 3.6 0.04 120 4.1 0.47 7.7 0.04 n – Detection Frequency The elements detected with the greatest frequency tend to be those that are highly soluble (e.g., boron) or known to be deposited from produced water (e.g., barium, strontium). Most of these elements are the same as those commonly detected in the leachate from drilling solids. Although the remaining elements are non-detect in the majority of samples, this does not provide any indication that concentrations are low because many samples have high detection limits. Removal of these non-detect values would only bias the overall distribution higher. This results in uncertainty and makes it difficult to draw further conclusions about the overall distributions. Organic Compounds EPA identified four studies that measured inorganic elements in the leachate from sludge. These studies reported samples collected from at least five states, though the amount of data from each state is variable (API, 1987; U.S. EPA, 1987; 2000a; LADNR, 1999). LADNR (1999) and U.S. EPA (2000a) reported a considerable amount more data than other studies collected from Louisiana and Pennsylvania, respectively. EPA did not identify information that could be used to further weight the data to obtain a more representative national distribution, such as the volume of waste generated in each state. Therefore, the data from each study was weighted equally. Table 5-21 presents the 50th and 90th percentile of the available data for organic compounds in leachate from sludge detected in at least half of samples. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-39 Table 5-21. Organic Compounds in TCLP Leachate from Sludge (mg/L) Vertical Wells Constituent1 Benzene Toluene Xylene N 50th 90th 254 / 390 32 / 56 39 / 51 0.18 0.01 0.04 14 5.0 1.8 n = Number of Samples Detected / Total These data show substantial enrichment of organic compounds in sludge leachate is possible. This is reasonable given the elevated concentrations in the bulk sludge. However, because available samples are drawn primarily from two states, it is difficult to draw conclusions about the overall distribution of concentrations and how frequently higher concentrations will occur. Radioisotopes EPA identified several studies that measured radioisotopes in the leachate from sludge. However, most of the studies only discussed results graphically or qualitatively, preventing a reliable comparison of the data (Pardue and Guo, 1998; Phillips et al., 2001; U.S. DOE, 2004). One study reported data on 226Ra leached from the sludge of two pits in Pennsylvania that stored produced water from horizontal wells (Zhang et al., 2015). This study reported leachate activities ranging between 98 and 378 pCi/L. One pit was sampled twice, with collection times set three years apart. The leachate from the two sampled sludges decreased somewhat from 378 to 268 pCi/L over three years, while the bulk activity of the sludge increased from 8.8 to 872 pCi/g. Over the same time, the barium content of the sludge increased substantially. This indicates that a majority of radium accumulated in the sludge is sequestered in barite. Zhang et al. (2015) suggests that the leachable radium is associated with carbonate minerals that form from reactions with atmospheric carbon dioxide. DOE (2004) reached a similar conclusion, noting that a greater fraction of radium was solubilized with nitric acid (HNO3) from sludge than pure barite scale. 5.5.3. Air Emissions Volatile organics and radon are the constituents most likely to be released from sludge into the surrounding air. EPA did not identify any studies that analyzed for volatile organics, but did identify one study that measured radon emanation. This study collected samples from Oklahoma (U.S. DOE, 1999b). Table 5-22 presents the 50th and 90th percentile of the available data for radon emanation from sludge. As previously discussed for scale, values are commonly expressed as an emanation factor, which represent the unitless fraction of the radon released that is able to migrate out of the material and into the surrounding air. Emanation factors may be used together with the activity of radium present to estimate an overall emission rate. Table 5-22. Radon Emanation from Sludge Isotope Rn-222 Emanation Fraction n 50th 90th 8/8 0.110 0.181 n = Number of Samples Detected / Total Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-40 The limited number and geographic isolation of available samples may skew the overall distribution, though the direction and magnitude of any bias is unknown. The measurements from sludge all fall within the range reported for pipe scale, but are most similar to samples of disturbed scale. This is expected because the physical properties of sludge more closely resemble disturbed scale. Individual particles of barite and other minerals found in sludge are generally smaller and more brittle than intact scale that plates out on the surfaces of well tubing and other equipment (Rood et al., 1998). The higher ratio of surface area to volume of sludge provides more direct contact with the surrounding air, which increases the rate at which radon can escape. 5.5.4. Summary – Production Sludge Available data show that production sludge can be generated wherever oil and gas operations occur. The primary source of constituent mass in the sludge appears to be deposition from produced water and other fluids that are handled along the production stream. Barite, similar to that found in pipe scale, can be a major component of the sludge. However, other settled solids such as returned fracturing sand, formation solids, and heavier hydrocarbons can also contribute mass. However, the composition of sludge can be highly variable and the lack of characterization data make it difficult to further refine distribution of constituent levels in this waste. One source of uncertainty associated with the available data are the age of the samples. Zhang et al. (2015) found that radium activity in sludge sampled from a pit increased by two orders of magnitude over the span of three years. Much of the accumulation is attributed to chemical precipitation, as the activity of the produced water did not increase during this interval. This is important because the accumulation of sludge is a gradual process. Thus, grab samples collected at random points during the operational life of a pit or tank could significantly underestimate typical constituent levels in the sludge at the time of disposal. Another source of uncertainty with the available data are the spatial variability of sludge within the pits and tanks. Solids suspended in produced water can settle out quickly once the velocity of the flow slows at an outfall to a pit or tank. This can result in hotspots of the constituents that concentrate in these solids. Some studies have reported higher levels of both total organic carbon and radium near the point of discharge into pits (Freeman and Deuel, 1984; Pardue and Guo, 1998). Concentrations can also vary based on which piece of equipment is sampled. Heavier solids and organics may settle out in equipment early in the production stream, while chemical precipitation may dominate deposition in pits and tanks used for water storage. Thus, grab samples from a single point in the production stream could underestimate or overestimate the overall constituent levels in the sludge sent for disposal. Contaminated Soil and Sediment Spills and other releases of wastes from exploration and production activities can result in the contamination of various environmental media (e.g., soil, surface water). EPA focused this discussion on soil and sediment because the constituents that precipitate out or adsorb to these media are the most likely to remain in place over time, which allows a more direct comparison of different samples. If undisturbed, contamination may remain in place for years. Constituents in ground and surface water Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-41 are more mobile and have greater tendency to mix within the media. This makes it difficult to aggregate these data without additional information (e.g., the time elapsed since the release, the flow rate of the water body). Therefore, further discussion of ground and surface water was limited to identification of damage cases based on site-specific information in Section 8 (Damage Cases). 5.6.1. Bulk Content In total, EPA identified twelve studies that provided data from nine states. The majority of these studies analyzed for radioisotopes. A few also analyzed for other inorganic elements, but none reported data for organic compounds. Barium is the one inorganic element measured with any frequency in these studies. Therefore, EPA chose to present the data for barium and radium together for comparison and discussion. Table 5-23 presents the 50th and 90th percentile of the available data for barium and radium in contaminated soil and sediment. Table 5-23. Barium and Radium in Contaminated Media State California Illinois Kentucky Michigan New York North Dakota Oklahoma Texas Wyoming n Barium (mg/kg) 50th 90th -14 / 14 17 / 17 ---8/8 1/1 1/1 -1,320 3,820 66,400 131,242 ---- 4,920 416,000 185,400 1,600 n Radium 226 (pCi/g) 50th 90th 16 / 16 24 / 24 92 / 92 20 / 20 16 / 16 23 / 23 61 / 61 34 / 34 18 / 18 0.80 8.4 12 153 1.1 0.76 11 14 7.4 30.4 403 904 1,626 4.2 5.4 406 254 42.4 n Radium 228 (pCi/g) 50th 90th 19 / 19 21 / 24 79 / 86 11 / 18 16 / 16 22 / 22 49 / 60 40 / 40 13 / 15 0.92 3.2 2.9 2.1 1.4 0.77 0.9 2.0 3.2 29 48 63 206 2.9 8.3 15.5 30 5.1 n = Number of Samples Detected / Total The bulk content of contaminated soil has the potential to be one of the most variable wastes generated. This is because it is dependent not only on the initial composition of the waste, but also on the magnitude of the spill and the characteristics of the soil. Many studies collected grab samples around areas of known or suspected contamination based on visible cues (e.g., salt scar, stunted plant growth) or hand-held survey equipment (e.g., spectrometer). As a result, it is not known whether these samples are representative of the overall contamination at each site. Spills are rarely uniform and individual grab samples may capture isolated “hotspots” or miss the impacted area entirely. More comprehensive sample collection would be needed to define the full magnitude and extent of contamination. Yet the available data demonstrate the potential for high radioactivity in contaminated soil and sediment. Maps provided by some studies show that the extent of contamination extends several hundred square meters across multiple locations at each site (U.S. DOI, 1997b; Zielinksi et al., 2000). Many of the available samples represent releases of sludge and scale, but some are attributed to releases of produced fluids based on the presence of nearby salt scars or waste management pits. To understand whether these different types of spills result in different types of contamination, EPA compared the available barium and radium concentrations in 25 samples. Several studies had reported the presence of barite in the soil and sediment samples (U.S. DOI, 1997a,b; Rajaretnam and Spitz, 1999; Zielinksi et al., 2000). This mineral is known to be present in sludge and scale, but might also precipitate Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-42 independently from liquid waste. Alternately, the dissolved radium might adsorb directly to the soil independent of barium. The result of this comparison is shown in Figure 5-9. Sediment data were not included because the available studies used acid digestion to analyze samples, which can significantly underestimate total concentrations of barium in scale. Figure 5-9: Relationship Between Barium and Radium in Contaminated Soil This graph indicates that co-precipitation with barium is the dominant mechanism for the initial deposition of radium. It also indicates that radium and barium tend to precipitate at a predictable ratio. Previous studies have reported a fixed relationship between losses of barium and radium from solution (Gordon and Rowley, 1957; Zhang et al., 2014). If this relationship reflects a standard rate of radium incorporation, similar relationships would be expected in other precipitated waste (e.g., sludge, scale). Therefore, EPA added an additional 34 samples of other wastes drawn from eight studies to the same graph. The result of this comparison is shown in Figure 5-10. Only one study diverged significantly from the relationship identified for contaminated soil (Fisher and Hammond, 1994). Therefore, data are presented without (left) and with (right) the data from this study for comparison and discussion. Figure 5-10: Relationship Between Barium and Radium in Different Deposited Wastes Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-43 About half the data reported by Fisher and Hammond (1994) agree well with those from other studies. The other half tend to have higher activities than predicted by the other studies, though a similar trend is present with increasing barium. The authors recognized this difference and noted that samples where the barite had deposited as a thin film on the surface of other solids typically had higher activities than those where scale precipitated independently. The authors speculated that higher levels were a result of faster and less-selective precipitation. Fast precipitation can result from changes in temperature and pressure as produced water is transported to the ground surface. This could mean that sludge deposited early in the production stream may have a higher ratio of radium to barium. This would align with the previous finding that the tanks closest to the wellhead tend to have higher total radium activity (U.S. EPA, 1993). 5.6.2. Leachate EPA identified three studies that analyzed leachate from contaminated soil or sediment. The activities measured in these studies are variable and reflect different wastes that had been mixed with different media. In addition, each study used a different leaching test to estimate potential releases. As a result, the available data are not directly comparable and each study is discussed separately:  Wilson and Scott (1992) collected three soil samples from around a former pipe cleaning operation in Louisiana. Soil samples had an average activity of 1,485 pCi/g 226Ra. Leachate samples were collected in accordance with EPA Method 1310B (Extraction Procedure Toxicity Test). The study reported leachate activities as the activity in the total volume of fluid, which converted to 3.5 and 5.6 pCi/L. The third sample was non-detect and the detection limit was not reported.  Pardue and Guo (1998) collected one sample of surface sediment from a water body in Louisiana located downgradient from a pit that held produced water. The sample had an activity of 581 pCi/g 226Ra. The sample was incubated for two months after adjusting the redox conditions to +600 mV (surficial aerobic sediment) and -250 mV (buried reducing sediment), though it was not specified how this adjustment was achieved. The resulting pore water was separated through centrifuge and measured. The study reported pore water activities per gram of sediment, which converted to 49 and 85 pCi/L 226Ra, respectively.  Rajaretnam and Spitz (1999) collected soil samples from an abandoned drilling site located on a Kentucky farm. The tank batteries on this site contained brine, sludge and other wastes. Two soil samples had an average activity of 880 pCi/g 226Ra. Leachate tests were conducted based on ASTM D5284-93 (sequential batch extraction) with modified extraction fluids containing HCl, NaCl, or Na2S intended to mimic acid rain, high-salinity produced water, or anaerobic conditions. The study reported releases around 1% of the total mass in the soil samples regardless of the extraction fluid used, which converted to approximately 570 pCi/L. Dissolved activity was similar for both extraction cycles. Several studies have reported that bacteria have the ability to reduce barite and liberate barium and radium. Some of the same studies also reported a stoichiometric imbalance between the amount of sulfate and barium released into solution following incubation with these bacteria. This imbalance was Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-44 attributed to either re-precipitation of barium as barium carbonate (witherite; BaCO3) or sorption onto the soil (Phillips et al., 2001; U.S. DOE, 2004). This cycle of dissolution and precipitation in response to changing redox conditions mirrors what is known about barium chemistry during shale formation. It is possible that radium will follow a similar cycle and either re-precipitate with barium or sorb to the soil, which would limit transport away from the point of release. Therefore, the composition of the soil could impact the degree to which radium is retained (IAEA, 2014). Landa and Reid (1982) found that the clay fraction of sediment that had received produced water discharge contained 50% of the radium mass, even though it comprised only 19% of the sediment. Any constituent mass that is adsorbed onto the soil or bound in carbonate complexes is likely to be mobilized more readily than from the original scale. 5.6.3. Air Emissions Volatile organics and radon are the constituents most likely to be released from contaminated soil and sediment into the surrounding air. EPA did not identify any studies that analyzed for volatile organics, but identified one study that analyzed for radon. As discussed previously, values are commonly expressed as an emanation factor, which represent the fraction of the radon released that is able to migrate out of the material and into the surrounding air. Emanation factors can be used together with the activity of radium present to estimate an overall emission rate. EPA identified a single study that analyzed samples collected from Illinois, Kentucky, Michigan, Oklahoma and Wyoming (U.S. DOE, 1999b). Because the emanation fraction is not a function of activity, EPA combined data from the different states into a single distribution. The ranges reported for each state are similar, which provides additional confidence that these data are representative of potential releases. Table 5-24 presents the 50th and 90th percentile of the available data for radon emanation from contaminated soil and sediment. Table 5-24. Radon Emanation from Contaminated Media Isotope Rn-222 Emanation Fraction N 50th 90th 65 / 65 0.139 0.243 n = Number of Samples Detected / Total Emanation fractions measured from contaminated soil all fall within the range reported for disturbed scale. This is expected because many of the samples are mixed with disturbed scale or sludge. Samples with contaminants adsorbed to the surface are expected to release radon at comparable rates because the radium is contained primarily on the surface of the material, which provides more direct contact with the surrounding air. Previous studies of emanation fractions from natural soil reported a similar range of emanation rates (IAEA, 2013). However, releases from soil and sediment may differ in the environment because saturation with water can inhibit releases of radon and other gases. 5.6.4. Summary – Contaminated Soil and Sediment Each of the wastes discussed in this document (i.e., spent drilling fluid, drilling cuttings or solids, produced water, sludge, scale) have the potential to introduce contaminants into the environment. Reports from Colorado, New Mexico, Oklahoma and Pennsylvania indicate that the most common Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-45 releases reported to these states are from produced water and drilling fluid (Kuwayama et al., 2017). Few reports were found for releases of sludge, scale and other solids. However, a number of samples reported in the literature are attributed to these wastes. Samples collected in Illinois, Kentucky, Michigan, Oklahoma and Wyoming all identified elevated levels of radium activity in soil attributable to historical contamination. It was estimated that, at the time of sampling, contamination had been present at several of these sites for 30 years or more. The available data show that there are similar concentrations in wastes generated today and so similar potential for contamination exists. The comparison of barium and radium in contaminated soil indicates there is a consistent relationship between the two precipitated elements. The presence of a predictable ratio indicates that the activity in sludge and scale will be proportional to the amount of barite present in these wastes. With further investigation, it might be possible to use the relationship between barium and radium to attribute historical contamination of unknown origin to spills of exploration and production wastes. Spills are most likely to occur near where the waste is produced (e.g., wellhead) or stored (e.g., reserve pit, tank battery) as a result of equipment failure or human error. As a result, proximity to equipment can be a useful criterion to locate historical spills along with other visual cues (e.g., salt scars). However, samples collected near the point of release will be biased toward contaminants that precipitate out of solution and remain insoluble. Some of the constituent mass may remain in solution because of the high ionic strength of produced fluids and be transported some distance downgradient before settling out. It will be considerably more difficult to locate and attribute this dispersed contamination. Conclusions Both hydraulic fracturing and directional drilling have the potential to impact the composition of E&P wastes. This review shows that there can be orders-of-magnitude variability in the composition of each waste type, though trends are apparent for certain constituents that might be used to predict where elevated constituent levels are more likely to occur. Some inorganic elements (e.g., lithium, molybdenum), organic compounds (e.g., benzene) and radioisotopes (e.g., radium) appear to be correlated with either the organic carbon content of the source rock or the salinity of the formation water. Horizontal wells are frequently drilled a greater distance through high-organic rocks with saline formation water and so higher constituent levels may be more common in the wastes from these wells, but similar orders-of-magnitude levels may also occur in the wastes from vertical wells. Therefore, it is likely that similar regulatory controls would be appropriate for the wastes from both types of wells. This review focused on publicly-available sources of data. There appears to be a substantial amount of additional data that is not in the public domain. Some studies make reference to databases, which EPA was not able to locate (Dingman and Angino, 1968; Rittenhouse et al., 1968; Collins 1969; U.S. DOE, 1991; Hitchon et al., 2000; U.S. DOE, 2004). Other studies provide summary statistics or qualitative discussion, but not the underlying data. It is often unclear how much data are contained in each database or study. However, the majority of these sources address produced water, which is already the waste with the greatest amount of data available. Therefore, further efforts to assemble existing data are unlikely to substantially improve the characterization of constituent levels (i.e., concentration and activity) present in and released from other wastes. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-46 The majority of available data reflect wastes as generated. However, wastes may then be intermingled with other wastes during storage or treated in preparation for disposal. Limited information is available about the impact that these management practices have on the composition and behavior of the wastes. Available data indicate that certain practices can increase the bulk concentration of some constituents, though the exact cause is not always clear. As a result, an evaluation of potential environmental impacts based on the wastes as generated could underestimate releases to the environment. Further sample collection and analysis would be needed to characterize potential releases to the environment during storage and subsequent disposal of E&P wastes. There are limited data available on the magnitude of releases through leaching or volatilization for any waste type. The data that are available reflect an assortment of analytical methods that capture different environmental conditions and cannot be reliably aggregated into a single dataset. Although more data are available on the bulk concentrations in these wastes, that alone is not a reliable indicator of how much mass can be released into the environment, particularly for wastes with recalcitrant mass. Further sample collection and analysis would be needed to fully characterize potential releases to the environment during storage and subsequent disposal of E&P wastes. Despite the various sources of uncertainty, the available data provide an estimate of constituent levels that can be used to determine which constituents are most likely to concentrate in each waste. Taken together with relationships identified among different waste types and different constituents, the data can also estimate where elevated concentrations are more likely to occur. High-organic-content rocks and high-salinity water are well correlated with elevated levels of inorganic and organic constituents and are defining features of hydrocarbon-bearing formations. As a result, elevated constituent levels are unlikely to be geographically isolated. Management of Exploration, Development and Production Wastes Section 5: Waste Characterization 5-47 6. State Programs States have the primary authority over the disposal of non-hazardous waste within their boundaries. Therefore, it is critical to understand how the different state programs are implemented for E&P wastes. The scope and specificity of state programs is variable. State programs vary, both among states and different regions of a state, to account for regional factors (e.g., formation type, meteorology) that impact the types of waste generated and the appropriate methods to manage those wastes. EPA has previously reviewed state programs, both as part of the 1987 Report to Congress and a more recent effort in 2014 (See Section 2: Summary of Agency Actions). However, state programs have continued to evolve to address emerging issues from hydraulic fracturing and other technological advances. Therefore, EPA conducted an updated review to better understand how state regulations currently address E&P waste management and to highlight inconsistencies, lack of specificity, or possible gaps in coverage. Methodology EPA evaluated the state regulations for 28 of the 34 oil and gas producing states, which represent more than 99% of the annual U.S oil and gas production by volume, according to U.S. Energy Information Agency data (U.S. DOE, 2018c,d).17 The six states with the lowest overall production were not included in this review (i.e., Alabama, Arizona, Maryland, Nebraska, Oregon, South Dakota). For each state, the latest version of E&P regulations were obtained electronically from the source identified on the state oil and gas agency website at the time of the review (February through December 2018). In some cases, such as California and Pennsylvania, the statute or enacting legislation was also obtained because it provided additional clarifying information on the waste requirements. Solid waste and radiation protection regulations were obtained in a similar manner. In addition, readily obtainable guidance and policy documents related to E&P waste were obtained from state agency websites. The review of guidance and other policy documents is unlikely to be as comprehensive as the review of applicable regulations because the Agency cannot guarantee that every potentially relevant document was identified. This review did not evaluate regional or field-specific requirements promulgated by state oil and gas boards. These special rules, often called “Orders” or “Special Field Rules,” may contain additional more stringent requirements for managing wastes and are unlikely to be less stringent than state regulations. Likewise, some counties, notably in Colorado and California, may place additional controls on oil and gas operators that are more stringent than state regulations. Disposal of RCRA-exempt wastes in Class II injection wells is allowed by permit in most states, and the associated regulatory program may fall under either the oil and gas agency or the environmental 17) This review of regulations did not include tribal regulations applicable in Indian country, because EPA was unable to conduct a similar review of tribal programs as many do not have the solid waste regulations compiled in a readily searchable online format. Generally, state laws do not apply in Indian country. The amount of tribal land varies across the United States but a majority is concentrated in EPA Regions 8, 9 and 10. EPA is fully aware that oil and gas exploration, development, and production operations take place in these areas, and so will continue to look at regulatory and program management responsibilities in tribal lands specific to managing wastes from these activities. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-1 agency. Several states specifically exempt underground injection control (UIC) disposal facilities, including the pits and tanks associated with these facilities, from the E&P regulations because they are covered under UIC facility rules. While UIC pits and tanks do not fall under E&P regulations in these states, EPA considers them waste management units. However, a comprehensive evaluation of state UIC regulations was outside the scope of this review. The first step in the review was development of an inventory of potentially applicable state regulations. Oil and gas, solid waste, and radiation protection regulations for each state were reviewed and the regulatory language related to 61 specific technical elements organized into 12 general topic areas were captured verbatim and documented in a spreadsheet (Appendix C: State Programs). This spreadsheet reflects the initial capture of regulations potentially applicable to the review. The inventory also included capturing the potentially applicable definitions associated with the regulations, dates of the regulation or subsequent updates (where available) and a link to the original document. Uncertainties EPA used the information compiled in the detailed spreadsheet to review state regulatory programs. These programs were found to vary not only in scope and specificity, but also in the language used to define different wastes and the relevant controls. This variability resulted in uncertainties when defining the regulatory coverage of some states. The following text provides an overview of how the Agency considered and addressed the major sources of uncertainty identified during the review to ensure that it was as complete and consistent as possible. Specificity: The specificity of state regulations differ for a range of topics, such as signage; groundwater monitoring; financial security; setbacks and location restrictions; run-on/runoff controls; inspections; spill notifications and corrective action. These regulations may specify controls for the individual well, the associated waste management units (e.g., pits, landfills), or site-wide. For record-keeping purposes, any of these requirements were considered evidence that regulatory controls are in place. Many states also include general statements that E&P operations shall not cause pollution to the land, water or air and shall not adversely affect environmental resources. These statements were sometimes part of the definition of “waste” or were stand-alone requirements in various parts of the regulations. States may have great flexibility in interpretation of such requirements, but EPA considered these general requirements to be too broad to address the specific protections for floodplains, endangered species, surface water and groundwater found in 40 CFR 257.3. Therefore, states that only include general protection requirements were listed as not having coverage with respect to 40 CFR 257.3. Not Allowed versus Not Addressed: EPA did not identify regulations or guidance from certain states for some practices, such as land application, beneficial use, offsite landfills or commercial facilities. In these cases, it was not clear based on the regulatory text whether the practice is prohibited in the state or unaddressed because it is not known to occur in that state. State agencies may have internal policy or case history that provide further guidance for these subjects. However, such documents are difficult to obtain and so these regulations are considered ambiguous. For these situations this review generally considered the practice to not be allowed (for counting purposes), but noted that it could be allowed Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-2 and controlled on a case-specific basis. In some cases, the practice was mentioned in other parts of the regulation but with unspecified controls, and so the practice was assumed to be allowed. Specific Requirements versus Supervisor/Agency Approval: Each state had a different approach to the content and level of direction in regulations for E&P wastes. Common approaches included:  Prescriptive set of rules and regulations with specific technical requirements across many areas that must be followed to receive permit approval or comply with permit by rule (common for high production states)  General or performance-based requirements that operators must incorporate into planning documents and application submittals that are reviewed and approved by the agency  Agency defined requirements on a site-specific basis (common for low production states) Where states provided performance-based requirements, such as “pit and tank bottoms must be impermeable” or “tank construction shall be compatible with waste and not leak,” the review considered there to be controls in place for record-keeping purposes. Deviations Allowed: Many states allow deviations to rules or specifications “with approval of the supervisor or director.” Allowance for modification beyond the written regulations can provide state programs with flexibility to address the rapidly changing technology in E&P production and the variability of site-specific conditions. For example, many pit liner regulations specify a material type or minimum thickness but allow the operator to propose an alternative, to be approved by the director. Because there is a specific requirement in place, this review considered the element to be incorporated in the state program and that the deviation did not alter protectiveness specified by the regulation. Level of Detail: States develop and revise regulations based on the conditions, practices and experiences within the state so it is not surprising that not all states address all topics with the same level of detail. However, it presents a challenge in comparing the comprehensiveness of regulation across states because EPA cannot be as familiar with which specific operations occur in each state. For example, pit definitions and the associated regulations in some states may address only a few types of pits and do not address certain other types. In other states, there are separate detailed requirements for each pit type. In this review for each pit element (e.g., permits, liners, fencing, netting, groundwater monitoring, leak detection), the presence of any topical regulation, regardless of the type of pit, was considered evidence that regulatory controls are in place. For example, if a state defines five types of pits and provides liner requirements for only one, this review concluded that the state did provide regulation on pit liners. Where possible, the state overviews identified the limitations of coverage or missing details. Definitions and Terms: The review identified several challenges with the definitions and terms used in the regulations. A common challenge was the use of ambiguous or undefined terms. For example, many states require waste to be disposed at an “authorized facility” but do not provide a definition or further details on the specific types of facilities that might be authorized to accept the waste. Other terms such as “significant,” or “appropriate,” or phrases such as “earthen pit,” and “above the water table” were Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-3 ambiguous and the level of protectiveness could not be identified but were still considered to provide regulatory control. As discussed above, definitions for pits are variable among states. Some states define pits by function (e.g., collection pit, reserve pit, emergency pit), and other states define pits by length of service (e.g., temporary pit, permanent pit) or content (e.g., freshwater pits, high chloride pits). Many states use a combination of classifications. Other reviews of E&P regulations note the same issue of inconsistent nomenclature for pits. STRONGER recognized this issue and provided guidance for consistent nomenclature in their 2017 Guidelines (STRONGER, 2017). Definitions for a specific term can vary among states. Across the states several terms are used to describe the non-salable liquids generated by producing oil and gas wells: brine, salt water, produced water and produced fluids. The discussions in this summary use the terminology defined by the state when discussing specific examples. The term “brine” is used when a specific state regulation is not being referenced. The review noted many other examples of multiple terms for the same concept. Conversely the review identified some terms that were defined differently by different states. The term waste, as defined in most state regulations, has a dual meaning. In addition to the traditional definition (byproduct or unusable material), it refers to the inefficient production of oil and/or gas such that the resource is lost or not recoverable. Unless otherwise specified, the traditional meaning is implied here. Definitions were used to support the evaluation of the level of detail and the coverage of state regulations. States with many definitions that included technical terms and subdivision of waste unit type (i.e. multiple pits or tank types) were deemed to be more comprehensive because they addressed a wider range of potential risks. Complexity of Regulations: E&P regulations cover many different technical areas and processes and are necessarily complex. Some state regulations were organized and presented in a centralized and comprehensive manner making it clear what was required and what was prohibited. For example, Oklahoma provided a list of E&P wastes, and a corresponding list of the acceptable disposal methods for each of the wastes. Some state regulations were complex and difficult to navigate because several different agencies had jurisdiction over different parts of the regulations. For example, The California Department of Conservation, Division of Oil, Gas and Geothermal Resources regulates oil and natural gas production in the state. The California Environmental Protection Agency has several departments, such as the Department of Toxic Substances Control, the State Water Resources Control Board and the nine Regional Water Quality Control Boards, and California Integrated Waste Management Board, all of which may be involved in the permitting process for oil and gas operations. Analysis of Specific Elements Across States EPA organized the review of state programs into 12 topic areas, which are further divided into 61 subelements. These elements were selected based on a review of elements incorporated for similar waste management units. For each state, an initial binary (yes/no) determination of whether regulations were in place for each of the 61 elements was assigned using the approach described above, supplemented by a second focused review of the regulatory text. The following discussion provides a summary of state programs organized around some of these topic areas. More comprehensive summaries for all topics on Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-4 a state-by-state basis and the spreadsheet used to document the regulatory text that formed the basis for this review are provided in Appendix C (State Programs). Specific examples provided in this summary are generally intended to demonstrate the range of requirements among different states and should not be interpreted to be representative of states not listed. 6.3.1. Waste Management Location Requirements (Siting and Setbacks) All states in this review except Missouri and Florida provide some form of location and siting requirements to address where oil and gas operations and associated waste management activities can be located. Siting requirements can be found in either the oil and gas rules or the solid waste rules depending on the nature of the waste operation (onsite versus offsite; temporary use versus permanent disposal). This review included review of state regulations only. Some counties and municipalities may have specific rules for oil and gas setbacks. Siting regulations can be found as broad general overarching requirements, or more commonly as dispersed rules associated with the construction or operation of specific waste units such as pits or tanks. Requirements commonly include setback distances from human and environmental resources including residences, schools, inhabited structures, roads, wetlands, floodplains, groundwater and wildlife habitats. At least five states (e.g., Alaska, Nevada, New Mexico, North Dakota, Utah) also consider seismicity and land stability conditions in siting for landfills or salt water treatment facilities that accept E&P wastes. Alaska also includes permafrost and ground thawing as site conditions to be considered in siting and design of drilling waste monofills. Texas, which accounts for the largest contribution to oil and gas production and number of wells drilled per year, does not have state-wide setback rules for E&P waste, and allows communities to set siting requirements. Applicability: Most rules focus on the siting of pits and tanks located onsite (within the well pad area) and only a few states discuss siting requirements for offsite commercial and centralized facilities for treating, recycling or reclaiming E&P wastes. Texas and Oklahoma have extensive sections in their regulations addressing siting criteria for offsite commercial and centralized facilities. North Dakota provides siting, construction and operation requirements for salt water handling facilities, which may be located onsite or offsite. Some states do not have siting requirements for drilling, completion and production pits or brine holding tanks because they are considered part of the drilling site/pad and proposed locations are included in the drilling permit application (APD) that is approved by the state. The APD form may include information on pit construction and location. Some states, including Colorado and Michigan have requirements for both the general well facility, and waste unit (pits) setbacks from environmental features such as groundwater or floodplains. Location and Siting Requirements: A direct comparison if location and siting requirements in different states is challenging because the coverage of waste operations varies among the states. Some states regulate siting based on the type of waste managed. Pits containing completion fluids and flowback water may have more stringent setback requirements than reserve pits and others only address specific situations (e.g., emergency pits). For example, the setback requirement from a continuously flowing watercourse in New Mexico ranges from 100 ft (temporary pits with low chloride fluids) to 300 ft (permanent pits and temporary pits with higher chloride fluids). Arkansas has residential and Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-5 environmental receptor setbacks for crude oil tank batteries and gas well produced fluids storage tanks but minimum groundwater depth is not specified for all mud, circulation or reserve pits. Several states (e.g., Colorado, Louisiana; Haynesville shale areas only, Ohio) provide different setbacks for urban and non-urbanized areas, as defined by the state. Three states (i.e., Florida, Missouri, Montana) do not provide residential, environmental or depth to groundwater setback distances for E&P wastes and allow the operator to propose locations and provide the distance to lease lines, water resources, buildings and water supplies to be approved by the agency. Michigan requires an environmental assessment of the site including identification of more than a dozen special hazards and conditions within 1,320 feet of the surface facility as part of the well permit process. Most states have a general rule that prohibits the siting of a well or waste management unit (specifically pits, tanks or landfarms) in a location that could allow pollution or damage to environmental resources. Solid waste requirements for siting landfills that accept E&P wastes may have more stringent requirements. All states with location or siting requirements have rules for siting wells or waste operations near floodplains or surface water resources, however, the definitions of the resources differ. For example, New Mexico and Pennsylvania provide a list of specific types of water bodies and environments for setbacks but many other states only reference setback from the 100-year floodplain. In Arkansas, a closed loop system is required for oil-based drilling fluid pits, mud pits or circulation pits within 100 feet of a pond, lake, stream, extraordinary resource waters, ecologically sensitive water bodies, or natural and scenic waterways. Of the 28 states in the review, only Colorado addressed siting related to endangered species in E&P regulations. Nine states included endangered species in landfill requirements applicable to E&P wastes. Tank battery siting is often included as part of the general well permit, but Arkansas and Idaho have specific setback rules for crude oil and brine tanks. Table 6-1 provides a summary of state requirements for location restrictions and setback distance. Table 6-1. Summary of Required Setback Distances in Select States. Number of States with Specific Setback Distances Resource Setback Requirement (Lower Bound) Setback Requirement (Upper Bound) Residences/Inhabited Structures 17 100 ft (OH) 1,000 ft (CO, NM) 1 mile (UT) Floodplains/Surface Water Resources 24 50 ft (OH) 1,500 ft from groundwater intake (IL) Groundwater 12 20 in below seasonal high groundwater table (9 states) 50 ft below the base of waste (UT) Siting and location of landfills permitted for disposal of E&P waste are generally regulated by the state solid waste agency. As noted before, the states classify exempt E&P wastes in a variety of ways (solid waste, non-hazardous waste, special waste, and industrial waste), each with different rules for landfill siting and location. Because of the long-term nature of disposal in landfills, solid waste landfill siting rules generally provide more stringent requirements and specificity in guidance for siting and location than oil and gas rules. For example, Class 1 solid waste landfills in Nevada may not be sited where Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-6 groundwater is less than 100 feet below ground surface, which is more than twice the distance of the most stringent E&P waste rule identified in this study. Similarly, states with rules for commercial operations for recycling or reclaiming oil, or disposal of brine tend to provide detailed siting requirements. Texas, for example, does not allow commercial recycling facilities in the 100-year flood plain, in a streambed, or in a sensitive area (as defined in regulations), and has a setback distance of 150 feet from surface water and supply wells. When reviewing applications for siting a commercial recycling facility, Texas considers waste type and volume, distance to residences and receptors such as wetlands, surface water, coastal resources, groundwater, and water supplies. 6.3.2. Tank Requirements (Onsite/On-Lease) Tank requirements may apply to one or more types of tanks (e.g., drilling fluid, produced water, oil). In some states, regulations for E&P waste tanks are incorporated in the above ground storage tank regulations. Regulations typically address the tank construction materials, secondary containment, and fluid/waste management practices. For this review, it was assumed that tanks holding crude oil can accumulate waste solids and so are considered potential waste management units. Tank Berms and Containment Specifications: Approximately 74% of states reviewed (18 of 28) have some requirements for tank berms or secondary containment. Some states require secondary containment for all tanks, while others have certain criteria. For example, in North Dakota, dikes for produced water tanks and berms at salt water handling facilities are required when deemed necessary by the director. In Colorado, secondary containment is required for “all tanks containing oil, condensate, or produced water with greater than 3,500 milligrams per liter (mg/L) TDS (not including water tanks with a capacity of less than 50 barrels) and must be constructed of steel rings or another engineered technology.” Nevada regulations state that “dikes or fire walls are required around permanent tanks for the storage of oil located within the corporate limits of any city or town, where tanks for storage are less than 500 feet from any highway or inhabited dwelling, less than 1,000 feet from any school or church or are so located as to be deemed by the Division to be a hazard.” Half of the states with berm requirements (9) provide a specific capacity for the secondary containment with most of them being 1½ times (or 150%) the size of the tank. Florida specifies two times the tank capacity, and New York regulations state that secondary containment must be able “to contain 110 percent of the volume of either the largest tank within the containment system or the total volume of all interconnected tanks, whichever is greater.” While the size and dimensions are not specified for any state, Utah regulations indicate “berms of sufficient height and width to contain the quantity” and Colorado regulations indicate the secondary containment “shall be sufficient to contain the contents of the largest single tank and sufficient freeboard to contain precipitation.” Regulations for five states (i.e., Colorado, Florida, Mississippi, North Dakota, West Virginia) indicate secondary containment must be impermeable or sufficiently impervious, while Idaho is the only state that provides a specific permeability value (1×10-9 cm/sec). In Colorado, operators are also subject to tank and containment requirements under Rules 603 and 604 (safety regulations for location and siting facilities and wells). Two states (Pennsylvania and Wyoming) refer to requirements under 40 CFR Part 112 (Spill Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-7 Prevention Control and Countermeasure Plans). Several states address construction and design requirements for piping that penetrates the dike, and the maintenance of the berm and bermed area. Tank Construction Material Requirements: Some requirements for tank construction are provided in regulations for 11 of 28 states reviewed. These states include general requirements indicating that tanks must be impermeable (i.e., Pennsylvania), constructed with compatible materials (i.e., Illinois, New Mexico, New York, North Dakota), and properly designed/constructed to contain liquids or minimize pollution (i.e., Colorado, Oklahoma, Virginia). Alaska regulations refer to API standards for tank construction, and Ohio regulations indicate that only steel tanks are allowed for burial. Colorado requires a synthetic liner under the entire bermed tank area and compliance with National Fire Protection Association (NFPA) Code 30 for tank construction. Netting for Open Tanks: Six states require netting for open tanks to protect birds and other wildlife from contacting possible hazardous fluids in open tanks and other open storage vessels (i.e., Arkansas, Illinois, Indiana, Montana, New Mexico, Texas). Oklahoma requires protection for migratory birds but does not make specific mention of netting. Modular Large Volume Tanks (MLVTs): These temporary tanks are constructed from modular components and used to hold large volumes of water for drilling, completion and production. The figures below are examples of MLVTs used for oil and gas operations. MLVTs are only addressed in regulations for two states. In Pennsylvania, modular aboveground storage structures that exceed 20,000 gallons require prior approval. Siting approval is required for site-specific installation of these modular structures at each well site. North Dakota regulations “allow portable-collapsible receptacles used solely for storage of fluids used in completion and well servicing operations, although no flowback fluids may be allowed.” MLVTs must utilize a sealed inner bladder and conform to API construction and installation standards. Tanks must have signage on all sides clearly identifying the fluid within. Tank Monitoring Requirements: Tank monitoring was found to be required in only a few state regulations. In Florida, “all tanks shall be installed, maintained, pressure tested, and protected against corrosion in accordance with generally accepted petroleum industry standards and practices.” Additionally, “tanks containing sour fluids shall be equipped so they can be gauged, sampled and the temperature measured at ground level.” Alaska regulations for crude oil tanks require an external method of leak detection and inspections after a significant seismic event, however it is unclear if these regulations apply to E&P waste fluids stored in tanks. Virginia and New York both require tank inspections. Several states require high level alarm and automatic shutoff systems on tank batteries to prevent overflows. Tank inspection requirements are quite variable. Many states do not specify inspections but require tanks to be maintained fluid tight or without leakage. Other states allow selfinspections (including visual observations of bermed areas and sumps) or require prescribed inspections annually (Virginia) or up to every 10 years (Alaska). Tank Solids Removal: Tank operation and management may include removal of solids (and any intermingled fluids) that accumulate in the bottom of crude oil and salt water tanks. Four states require permits for tank bottom removal (i.e., Kentucky, North Dakota, Pennsylvania, Texas). Although other Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-8 states may not require permits for tank bottom removal, some do provide procedures for managing tank bottom wastes. In Illinois, a permit is not required but approval may be needed for some non-regulated disposal options. Oklahoma requires permits for commercial tank bottom reclamation facilities. In Colorado, tank bottom removal does not require a permit, but the disposal facility must be permitted. Wyoming regulations indicate “dispose of produced water, tank bottoms, and other miscellaneous solid waste in a manner which is in compliance with the Commission's rules and other state, federal, or local regulations.” Regulations for managing tank bottoms are often included in disposal requirements such as beneficial use, land application, and commercial reclamation/recycling. In Kentucky, recycling of tank bottoms is encouraged as a best management practice. 6.3.3. Pit Construction and Operation Requirements Pits may be used at any stage of E&P operations (e.g., drilling, completion, workover, production). A wide range of both fluids and solids can be stored in pits. All 28 states in this review regulated the construction or operation of pits in some manner. However, one state, Missouri, does not provide technical requirements for pits for any of the topic areas discussed below. Most states have developed regulations based on some type of classification, generally based on the intended use for the pit and/or the type of materials held in the pit. These classifications reflect the anticipated level of risk from use of pits over time. For example, pits used to hold produced water have a higher potential for risk than those that hold fresh water and so may have more stringent design requirements. Additionally, some states classify pits based on their expected time of use (temporary or permanent). Production pits holding brine over long periods of time are generally considered to represent a higher risk of release than pits used during the much shorter drilling process. Pit Types: The number of types of pits defined in the regulations varies considerably among the states reviewed. At one extreme, Texas regulations describe more than 15 different types of pits using both pit names or pit function. At the other, New York and Pennsylvania only identifies a single category of “brine pits” in the regulations. The different approaches used to define pits makes comparison and analysis of regulations difficult. Because most state E&P regulations are organized by process (e.g., permitting, drilling, production), pit regulations are often dispersed throughout the rules. Many states regulate pits based on the general stage of the process (e.g., drilling, production, disposal). Within these categories there are often further subdivisions that reflect the specific use (e.g., reserve pit, circulating pit, skimming pit, flare pit) or pit contents (e.g., fresh water, drilling fluids, produced water). Some pit types, including emergency pits, burn pits, gas processing plant blowdown pits and centralized or multi-well pits do not fit directly under these categories and are often addressed separately. EPA also identified structures in some state regulations referred to as “impoundments.” In West Virginia, an “impoundment” only refers to earthen structures for fresh water. In Alaska, New Mexico and Ohio, an “impoundment” may be lined and hold waste materials. In some states, impoundments greater than a certain size are regulated and permitted as dams. Many states have revised pit and drilling regulations since 2011 and specifically address existing pits that do not conform with the updated regulations. Generally, non-conforming pits must be closed within 3 to 12 months, brought into conformance, or receive approval for continued use by the state Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-9 agency. A few states have addressed historical pits (“inactive pits”) that may not have been constructed, operated or closed in accordance with current rules, and either provide regulations for inventory of such pits (e.g., Indiana) or a program to address remediation of these pits. The assessment and remediation programs are generally under the direction of the state environmental agency. Commercial Pits and Centralized Pits: Some states with significant oil and gas production, such as Texas, Oklahoma, Wyoming and New Mexico, have separate regulations that cover commercial E&P waste management facilities. In 6 of the 28 states reviewed, centralized pits used to support multiple wells are regulated separately from individual well site pits primarily because of their large volume and unique design considerations (i.e., Colorado, Pennsylvania, New Mexico, Oklahoma, West Virginia, Wyoming). Centralized pits associated with disposal wells are not consistently addressed in the pit rules in all states. Although Class II disposal wells are regulated under the Safe Drinking Water Act’s UIC program, the aboveground pits and other waste management units are not. Oklahoma includes detailed specifications for surface facilities (pits) associated with commercial injection wells, but most other states do not specifically address the subject or make a distinction between salt water holding pits and pits associated with permitted disposal wells. Prohibited Pits: Almost half the states reviewed (13 of 28) identified specific types of pits that are prohibited; however, no state prohibits pits entirely. Many states include a general prohibition on pits that would cause pollution or release to the environment. The most common prohibitions on specific types of pits are those that contain a specific type of waste (e.g., oil, brine, salt cuttings), that are unlined (sometimes called “earthen”), are permanent (i.e., present longer than a specified duration), and unpermitted. Other specific prohibitions include those constructed on fill material, those associated with particular well types, that are in areas that are hydraulically linked to groundwater or surface water, and that are within a certain distance of specific zones, such as residential areas. Permits: Permits are required for pits in 16 of the 28 states reviewed; however, in some states permits are only required for certain types of pits. For example, only commercial brine pits in Texas and pits holding greater than 5,000 barrels of fluid in Virginia require permits. In many of the states where a specific pit permit is not required, the pit is permitted as part of the APD or covered as permit by rule. In New York and Alaska, permits are not required but a management plan for drilling fluids (including pit information) is required as part of the well APD permitting process. Freeboard: Most of the states reviewed (20 of 28) include some requirement for maintaining adequate freeboard. Sixteen of the 20 states include specific requirements, which typically range from 1 to 3 feet. Some states have different freeboard requirements based on various pit types. For instance, Kansas provides different values: drilling, work-over, burn and containment pits have a minimum freeboard of 12 inches, while emergency and settling pits have a minimum freeboard of 30 inches. Some states also only provide values for particular pit types. Utah, for example, specifies a 2-feet of freeboard for evaporation ponds only. Four other states (i.e., Indiana, Ohio, Texas, Wyoming) do not provide specific values for freeboard but rather indicate “adequate” or “sufficient” size/capacity of the pit is necessary. Table 6-2 provides a summary of state-specific requirements freeboard. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-10 Table 6-2. Summary of Freeboard Requirements for Pits. Freeboard States 1 ft 3 – KS (drilling, workover, burn and containment pits), KY, MS (brine pits) 2 ft 11 – AK, AR, CO, ID, LA, MS, OK, PA, TN, VA, WV (centralized pits) 2.5 ft 1 – KS (emergency and settling pits) 3 ft 2 – MT, NM 75% capacity 1 – FL Signage: Most states (19) require signage for the site, though seven (i.e., Colorado, Indiana, Mississippi, New Mexico, North Dakota, Oklahoma, West Virginia) require signage for pits specifically. Five of these states specify signs for particular pit types. For example, offsite reserve pits and commercial disposal pits in Oklahoma, temporary salt water storage pits in Mississippi, and freshwater in both pits and portable-collapsible receptacles in North Dakota all require specific signs. New Mexico regulations specify that “the operator shall post an upright sign not less than 12 inches by 24 inches with lettering not less than 2 inches in height in a conspicuous place on the fence surrounding the pit or below-grade tank, unless the pit or below-grade tank is located on a site where there is an existing well…that is operated by the same operator.” Fencing and Netting: Eighteen states have fencing requirements for pits. Some states require fencing only for certain pit types. For example, North Dakota requires fencing for open pits and ponds that contain salt water or oil, while fencing is not required for drilling or reserve pits used solely for drilling, completing, recompleting or plugging, except beyond 90 days of operation. Ten states do not have fencing requirements for pits with Mississippi regulations specifically stating that fencing is not allowed to ensure agency field personnel have access to facilities for inspection and regulatory enforcement purposes, that first-responders (fire, sheriffs, emergency medical personnel, etc.) have ready access in the event of emergencies (fires, explosions, etc.), and that site personnel have a ready means of egress or escape from such facilities in the event of emergencies. Ten of the 18 states that require fencing also require netting. North Dakota regulations state that all pits and ponds that contain oil must be fenced, screened and netted. Colorado regulations state that “where necessary to protect public health, safety and welfare or to prevent significant adverse environmental impacts resulting from access to a pit by wildlife, migratory birds, domestic animals, or members of the general public, operators shall install appropriate netting or fencing.” Idaho does not specify fencing or netting directly but rather “site-specific methods for excluding people, terrestrial animals and avian wildlife from the pits.” There are no states that require netting without fencing. Table 6-3 provides a summary of the specific state requirements for fencing and netting. Idaho was counted as both fencing and netting for accounting purposes. Table 6-3. Summary of Required Fencing and Netting for Pits. Requirement Number States Fencing Only 8 IL, MI, LA, OH, OK, PA, VA, WV Fencing and Netting 10 CO, ID, IL, IN, MT, ND, NM, TX, UT, WY Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-11 Liners: Twenty-seven of the 28 states require liners for at least some types of pits. Most states (22 of 28) clearly state that liners are required by providing specifications, such as pit types, liner types and liner requirements. Other states, like Nevada, are more indirect and imply that a liner is required by prohibiting unlined pits. Michigan prohibits earthen pits for well completion fluids, produced fluids and tank bottoms but does not define earthen pits so it is unclear if lined pits are included in the prohibition. Some states provide specifications for liners, including thickness and material. Liner thickness typically ranges from 10 to 60 mils, and materials are often synthetic or materials with equivalent performance, such as compacted clay, as approved in each state. Colorado regulations are substantial and specify different pit types/waste characteristics and associated liner requirements. Idaho regulations indicate that all liners should have a minimum permeability of 1×10-9 cm/sec, and thicknesses of 20 mils for reserve, well treatment and other short-term pits and 60 mils for long-term pits. In contrast, New York regulations state that a “watertight material” is required for brine pits. In Tennessee, liner seams should be 4 inches wide and welded. Seams are not allowed in Michigan. State requirements for liners may vary by pit type. Some states have different requirements for liners based on the material being contained, while others require liners for some liquids but not others. Arkansas regulations, for example, require synthetic or compacted clay liners for reserve pits, synthetic or bentonite liners for drilling mud, and concrete liners for mud and circulation pits. In Illinois, fresh water reserve pits do not require liners but other pits do. Mississippi only requires temporary salt water pits be lined with an approved impervious material. Michigan specifies secondary containment (i.e. liners) for flare pits. Leak Detection and Monitoring: Ten of the 28 states require leak detection and monitoring, though specifications provided in the regulations varies. For example, leak detection/monitoring is only required for long-term pits (more than one year) in Idaho, for brine pits in Texas, and centralized pits in West Virginia. The type of detection/monitoring also varies by state. For instance, Indiana requires visual inspections while Colorado requires the use of pit level indicators within designated setback locations. Two additional states (i.e., Utah, Wyoming) may require leak detection/monitoring in sensitive areas, as required by the agency or specified in a permit. Berm Requirements: Seventeen states include requirements for berms with varying degrees of detail. Four have requirements for the site, but not pits specifically (i.e., Florida, Ohio, Virginia, West Virginia). Six states (i.e., Alaska, Indiana, Mississippi, New Mexico, Oklahoma, Texas) have general requirements for pits indicating, for example, that “pits shall be protected from surface waters by dikes and drainage ditches” (Mississippi) or that berms should be “adequately sized” to prevent pit inundation (Indiana). Alaska states that “if practical, confinement diking in construction of a reserve pit must be avoided. If confinement dikes are necessary, they must be kept to a minimum.” Five states (i.e., Idaho, Kentucky, North Dakota, Pennsylvania, Tennessee) provide specific berm requirements for pits. For example, berms in Tennessee should have a 2:1 slope and a width of 2 feet. Idaho regulations state that the top of bermed pit walls be a minimum of 2-feet wide and “pits that have constructed berms ten or Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-12 more feet in height or hold fifty acre-feet or more of fluid must also comply with the dam safety requirements.” Depth to Groundwater: A minimum depth to groundwater for pit siting is required by 12 of the 28 states reviewed. Seven states provide specific depths that range from 20 inches in Pennsylvania and West Virginia to 25 feet in Oklahoma. Table 6-4 provides a summary of the specific state requirements for depth to groundwater. Table 6-4. Summary of Required Depth to Groundwater for Pits. Minimum Depth to Groundwater 1.7 ft 4 ft 5 ft 10 ft 20 ft 25 ft States PA, WV (centralized pits only) MI KS, LA AR WY OK Three remaining states provide more tailored requirements. Tennessee regulations state that, “in areas where groundwater is close enough to the surface that it will be encountered in construction of a pit, pits shall be constructed above ground, or the operator shall use a closed-loop system.” Utah uses a ranking approach to evaluate potential impacts based on pit location. Surface to groundwater depth is one criterion considered in this evaluation, and if less than 25 feet, a closed-loop system should be considered instead of constructing a pit. In New Mexico, temporary pits containing low-chloride fluid may not be located where groundwater is less than 25 feet below the bottom of the pit. Groundwater Monitoring: Over half of the states reviewed (15 of the 28) address groundwater monitoring either on a site-wide basis or specific to an E&P waste management unit (e.g., pit, landfill). Eight of the 15 states address groundwater monitoring on a site-wide basis (i.e., Colorado, Illinois, Michigan, Nevada, Ohio, Tennessee, Utah, Virginia), rather than for any specific type of E&P waste management unit. In Wyoming, however, baseline groundwater monitoring is conducted for the entire drilling site and may be also required for an E&P waste pit if it is located in a sensitive area. The remaining seven states (i.e., California, Louisiana, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia) require some type of groundwater monitoring for specific E&P waste management units. For example, Texas requires groundwater monitoring for commercial recycle/reclaim pits, brine pits and other types of pits if required by a permit. Oklahoma requires groundwater monitoring for flowback pits with capacities greater than 50,000 barrels and brine disposal well pits. Pennsylvania requires groundwater monitoring for centralized impoundments and unconventional well construction. North Dakota states that monitoring is required, which may include groundwater monitoring, for all buried or partially buried structures at treatment plant facilities. Inspections: Eleven states include requirements for the inspection of pits. The different approaches used to define pits makes it difficult to further summarize the requirements. The regulations often specify the type of pit requiring inspection, which varies considerably among the states: Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-13  Illinois and Indiana require inspection of concrete storage structures, which are allowed to be used as pits for production and waste materials.  Louisiana requires inspection of reserve pits.  Mississippi does not require inspection of pits, but the state must be given the opportunity to inspect the pit prior to use.  New Mexico requires that the state be given the opportunity to inspect pits prior to use. The following inspection activities are required: o A minimum of daily inspections for temporary pit containing drilling fluids while the drilling or workover rig is on location, then weekly so long as liquids remain in the pit. o Weekly inspections of permanent and multi-well fluid management pits with the use of an on-site log while the pit has fluids at least monthly until the pit is closed. Inspections will include monitoring of the leak detection system during operation and before the system is covered. o If netting or screening is not feasible for a permanent pit or multi-well fluid management pit, the operator shall inspect for dead migratory birds and other wildlife on a monthly basis.  North Dakota requires all reserve pits to be inspected prior to installation of the liner and use.  Oklahoma requires inspections only for flowback water pits.  Pennsylvania requires inspections at least once a year for onsite brine or residual waste disposal.  Texas requires inspections of all brine pits and commercial recycle/reclaim pits, as well as others as specified by permit.  Tennessee requires pre-permit inspections for all “pollution control structures.”  West Virginia requires inspections of pits and impoundments with a capacity greater than 5,000 barrels (at conventional wells) and all centralized pits/impoundments prior to placement of any fluid, every two weeks for the life of the pit, and within 24 hours of significant rainfall (2 inches or more within a 6-hour period). For other types of pits, the state must be notified and given the opportunity to inspect prior to use.  Wyoming requires periodic inspections of pits by the operator (weekly at a minimum) with documentation of such inspections sent to the Supervisor (state) at their request. 6.3.4. Pit Closure Requirements Regulations were reviewed for several pit closure requirements including removal of waste material prior to closure, timing for pit closure, inspection and sampling. A total of 22 of the 28 states directly address pit closure requirements. One of those states (Kentucky) includes the requirements in an Operator’s Manual instead of regulations. Tennessee regulations do not specifically address pit closure but require removal of fluids from pits “as soon as practical after fluids have accumulated in them.” Table 6-5 provides a summary of the general types of pit closure requirements identified in this review. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-14 Table 6-5. Summary of Pit Closure Requirements. Number of States Specific States Liquids Removal 23 AR, CA, CO, FL, ID, IL, IN, KS, KY, MI, MS, MT, ND, NM, OH, OK, PA, TN, TX, UT, VA, WV, WY Solids Removal 17 AR, CA, CO, FL, ID, IL, IN, KS, KY, MT, ND, NM, OH, PA, TN, TX, UT, WY Closure Timeframe 22 AR, CA, CO, ID, IN, KS, KY, MI, MS, MT, ND, NM, NV, NY, OH, OK, PA, TN, TX, VA, WV, WY Inspections 10 CO, ID, LA, MS, ND, OK, PA, TX, UT, WV Criteria Removal of Liquids and Solids: Most states (23 of 28) require removal of liquids prior to pit closure. Some states specify the types of pits that require liquid removal. For example, drilling, reserve and temporary pits in North Dakota and hydraulic fracturing fluid pits in Ohio must have liquids removed prior to filling and compaction. Details about the method of liquid removal or disposal are provided in some regulations and may include disposal at an appropriate facility, offsite reuse or downhole disposal (i.e. injected liquids and semisolids, or placement of cuttings in the annular space of a plugged well). Illinois regulations specifically state that “all oilfield brine and produced waters shall be removed and disposed of in a Class II UIC well.” In Colorado, Oklahoma, Utah and Wyoming, natural evaporation is an accepted method of removal. Six of the states that require removal of liquids do not require removal of solids prior to pit closure (i.e., Michigan, Mississippi, Oklahoma, Pennsylvania, Virginia, West Virginia). Michigan regulations state that drilling mud pits with waste in place shall be stiffened (i.e., earthen materials are mixed with the pit contents to provide physical stability and support for the pit cover) prior to encapsulation. Sixteen of the 28 states reviewed require removal of solids in some instances prior to pit closure. Arkansas, Texas and Wyoming specify the types of waste that either require removal or may remain in the pit. North Dakota regulations specify that contents of any earthen pit/receptacle be removed and disposed, while waste in drilling and reserve pits be encapsulated in the pit and covered. Idaho requires all pits to remove and dispose of solids and the pit liners. Regulations in four states (i.e., Alaska, Missouri, Nevada, New York) do not mention removal of liquids or solids prior to pit closure. However, Alaska regulations include a general requirement that “upon completion the operator shall proceed with diligence to leave the reserve pit in a condition that does not constitute a hazard to freshwater.” Closure Schedule: A total of 22 of the 28 states provide a schedule for pit closure. Some include specific requirements while others are more general. Timeframes typically range from 30 days to 12 months after the completion of particular site operations. For example, in North Dakota, pits should be reclaimed according to the following schedule: earthen (unlined) pits within 30 days after operations have ceased, reserve pits within 30 days after the drilling of a well or expiration of a drilling permit, and reserve pits within a reasonable time but not more than one year after the completion of a shallow well. Nevada regulations indicate pit closure be conducted “as soon as weather and ground conditions permit, upon final abandonment and completion of the plugging of any well.” Colorado regulations for Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-15 reclamation are not specific for pits but indicate that reclamation for wells be completed within three months on crop land and 12 months on non-crop land. Inspection and Sampling: Seven states require some form of inspection and sampling prior to pit closure (i.e., Colorado, Idaho, Louisiana, Oklahoma, Texas, Utah, West Virginia). Idaho regulations state “the owner or operator must notify the Department at least 48 hours prior to removal of the pit liner so an inspection may be conducted.” Idaho also requires the testing of residual fluids and any accumulated solids in the pit to determine which disposal facility can accept the material. In Texas, inspections are required for commercial recycling/reclamation pits, or as required by a permit for other pit types. Texas also requires the testing of soils prior to closure. Testing parameters include pH, TPH, BTEX, as well as numerous metals. Colorado requires an inspection for overall drill site reclamation but not for pits specifically. Two states (i.e., Mississippi, Pennsylvania) require inspections, but no sampling. In Mississippi, emergency pits require inspection following the emergency period. Arkansas only requires sampling. Inspection and sampling are not required in Wyoming but may be determined to be necessary based on site-specific conditions. Inspections are not required for North Dakota, but approval is needed prior to pit reclamation. EPA identified no state regulations that require groundwater monitoring or testing subsequent to pit closure, but such a requirement could be included by the state agency in an individual well or pit permit. Several states that require sitewide baseline groundwater monitoring also have requirements for monitoring post well construction. Virginia, for example, requires groundwater monitoring consisting of initial baseline groundwater sampling and testing followed by subsequent sampling and testing after setting the production casing or liner. Pennsylvania requires that bodies of water and watercourse over and adjacent to horizontal directional drilling activities must be monitored for any signs of directional drilling fluid discharge. Financial Assurance: For all states reviewed, separate financial assurance is not required for pit closure. Instead, if required, it is included in the general permit/bond for the well or overall facility. 6.3.5. Spill Notification and Corrective Action A total of 26 of the 28 states reviewed included requirements for notification of spills in their regulations. Many of these regulations are not specific to a waste type and can include spills of crude oil or raw materials, neither of which is covered under the RCRA exemption. Some states refer to spills as “releases” or “nonpermitted or unauthorized discharge.” New Mexico separately defines “major release” and “minor release,” with different requirements for each. Some states (i.e., Idaho, Montana, Nevada, Utah, Wyoming) discuss spills in sections with other accidents or emergencies, such as fires, lightning strikes or blowouts. Other states (i.e., Colorado, Illinois, Indiana, Kansas) have separate “spill” sections. Mississippi regulations only address spill notification and corrective action in offshore rules. Notification: For the 26 states with spill notification requirements, immediate notification is required following a spill or discharge from a waste management unit, especially for an uncontrolled spill/discharge that enters (or threatens to enter) nearby surface water or impact groundwater. Immediate notification is generally required to the Department/Commission/Division and a timeframe is often specified, ranging from 30 minutes to 24 hours. Some states (e.g., Michigan) do not give a Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-16 specific timeframe but instead require the incident to be reported immediately or promptly. This initial notification is often communicated verbally, although North Dakota does have an initial online notification system that requires the location, type of incident, cause of the incident, volume released, volume recovered, potential environmental impacts and actions taken. A follow-up written report is typically required within five to 15 days, depending on the state. Additional requirements for initial spill notification can vary based on quantity of material spilled. Table 6-6 provides a summary of the spill notification requirements for Wyoming and New Mexico. Table 6-6. Summary of Spill Reporting Requirements in Select States. State New Mexico Wyoming Spill Type/Material Quantity Volume that may with reasonable probability be detrimental to water or exceed specified standards Not specified Major release >25 barrels Minor release >5 and <25 barrels Verbal report: immediately, within 24 hours Uncontained spill or authorized release which enters, or threatens to enter, waters of the state Any/All Contained spill <1 barrel (42 gallons) Contained spill >1 and <10 barrels Contained spill Timeframe/Report Type Written notice: 15 days Verbal report: immediately, within 24 hours Written notice: 15 days Written notice: 15 days Verbal report: by next business day >10 barrels Written report: 15 working days Reporting not required (maintain record of incident) Written report: 15 working days Verbal report: Next business day, Written report: 15 working days States have a minimum spill volume threshold at which notification is required, which range from any amount spilled (e.g., Kansas, North Dakota, Utah) to 2,100 gallons (e.g., Nevada). Most states have a minimum quantity between 210 and 420 gallons (i.e., five to ten barrels). Volume requirements may also vary for the type of fluid spilled. Some states provide general descriptions (e.g., deleterious substances18) while others are more specific, such as crude oil, brine or produced water. For example, in both Arkansas and Illinois, immediate notification is required for a spill of one barrel of crude oil and/or five barrels of produced water. The type of notification required can further vary based on different waste characteristics or site conditions. For example, in Montana, immediate notification is required for the following cases: “(a) the spill, leak, or release of more than 50 barrels of oil or water containing more than 15,000 parts per million (ppm) TDS; (b) the spill, leak, or release of any amount of oil or of water containing more than 15,000 ppm TDS that enters surface water or groundwater; (c) the spill, leak, or release of any amount of produced water that degrades surface water or groundwater.” Colorado regulations indicate that notification is required within 24 hours of the following: (1) a spill/release of any quantity that impacts or threatens to impact any waters of the state, a residence or 18) The term “deleterious substance” has a broad range of definitions across the states using the term. For example, in Montana it includes all CERCLA and RCRA hazardous material and waste definitions, and any petroleum product, whereas in Oklahoma and Mississippi the term is more limited to oil and gas operations “…any chemical, salt water, oil field brine, waste oil, waste emulsified oil, basic sediment, mud, or injurious substance produced or used in the drilling, development, production, transportation, refining, and processing of oil, gas and/or brine mining.” Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-17 occupied structure, livestock or public byway; (2) a spill/release of one barrel or more of E&P waste or produced fluids is spilled or released outside the berms or secondary containment; or (3) a spill/release of five barrels or more regardless of whether the spill/release is within the berms or other secondary containment. Corrective Action: Twenty of the 28 states reviewed include discussion of corrective action in the regulations. Some states (e.g., Montana, Utah), provide general statements indicating that leaks/spills be contained and cleaned up promptly. Some (e.g., Colorado) include specific cleanup criteria for specified contaminants in soil and groundwater, while others (e.g., Kansas) provide details for the corrective action approach. In Kansas, “the following cleanup techniques shall be deemed appropriate and acceptable to the commission: physical removal, dilution, treatment, and bioremediation.” Regulations in Illinois provide detailed approaches for crude oil spills as well as produced water spills, while Texas regulations provide similar details specifically for soil contaminated by crude oil in nonsensitive areas. Additionally, some states (e.g., Michigan, Virginia) include details in a spill management or abatement plan. Some regulations provide timeframes for performing corrective actions. For example, spills greater than 42 gallons or that pollute or threaten to pollute the waters of Pennsylvania require an initial written report within 15 days and a site characterization report within 180 days to determine the extent of contamination resulting from the spill and document initial response actions. In Idaho, leaks that develop in a pit or closed-loop system require corrective action within 48 hours to include removing all liquid above the damage or leak line. 6.3.6. Offsite Landfills Regulations for disposal of E&P wastes in offsite landfills may be found in either the state regulations for E&P waste, solid waste or both. To determine if wastes can be placed in offsite landfills it may be necessary to consult both sets of regulations. Therefore, this review considered both E&P and solid waste regulations. However, cross references are sometimes unclear or inconsistent because solid waste regulations often do not specifically discuss E&P wastes or define the type of landfill required for disposal. Offsite Disposal Allowed: Twenty-five of the 28 states reviewed address offsite landfill disposal of E&P wastes in regulations. The three remaining states (i.e., Missouri, Mississippi, Tennessee) may allow offsite disposal, but it was not clear in the regulations reviewed. For example, Mississippi solid waste regulations delegate exclusive authority for disposal of nonhazardous oilfield waste, both commercial and noncommercial, to the Mississippi Oil and Gas Board, but offsite disposal methods are not addressed in the regulations. A fact sheet regarding disposal of wastes from the BP oil spill indicates that landfills are an acceptable disposal option if waste meet the state and federal definitions of non-hazardous (MSDEQ, 2010). Some state regulations do not require E&P wastes be disposed in a particular type of disposal facility but rather state “a permitted facility.” When the type of facility is specified, municipal solid waste landfills are the most common (e.g., Indiana, Kansas, Montana, Pennsylvania, West Virginia). Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-18 Municipal solid waste landfills are designed according to regulations from 40 CFR Part 258, which include liners and groundwater monitoring, among other requirements, and so are generally considered protective provided that the waste meets acceptance criteria. Other offsite disposal options may include industrial landfills, special waste landfills, commercial facilities and recycling facilities. For example, Alaska regulations specify drilling waste monofills as a particular type of permitted landfill. E&P wastes in Colorado may be disposed at permitted commercial disposal facilities, while New Mexico regulations specify recycling facilities. Oklahoma regulations state the type of facility for disposal of E&P wastes is based on either Department of Environmental Quality approval or landfill permit requirements. States generally classify landfills based on the risk from the wastes allowed, and set different protective criteria (design, operation, and monitoring) for each type of landfill. Details about allowable waste types are provided in some of the state regulations but generally do not address every individual waste type. Ohio regulations indicate that a solid waste facility is acceptable for “drill cuttings that have come in contact with refined oil-based substances or other sources of contamination.” In Illinois, waste classified by the state as naturally occurring radioactive material (NORM) with activities at background levels may be disposed at a permitted non-hazardous special waste landfill, while NORM waste above background levels requires disposal at a waste facility permitted by the Illinois Department of Nuclear Safety. Most regulations, however, focus on pit wastes, with less attention to tank wastes and little mention of other exempt wastes (pipe scale, pigging wastes, produced sand, dehydration and sweetening wastes, spent gas plant filter material, and associated wastes). North Dakota appears to be the only state with regulations to explicitly identify filter socks and other filter media in E&P regulations. Waste Testing: Testing of waste prior to offsite disposal is required in seven of the 28 states reviewed (i.e., California, Idaho, Illinois, Louisiana, New Mexico, Oklahoma, Texas). In Illinois, testing is necessary only for wastes that might have NORM. Idaho requires routine characterization of waste received for facilities permitted to receive E&P waste. Wyoming and Utah do not require testing for all wastes, but it may be deemed necessary by the Supervisor/Division on a site-specific basis. Site specific waste control plans in New York may also include a requirement for testing. Individual disposal facility permits may require testing of wastes prior to acceptance. Daily Cover: The use of E&P wastes as a daily cover was not specifically addressed in any of the state regulations reviewed. A report prepared for the West Virginia Department of Environmental Protection noted that the drill cuttings received often have too high a moisture content, which makes it difficult to meet specifications for compaction (WVDEP, 2015). However, a report by the ANL noted that stabilized oil and gas wastes have been used as daily cover in Louisiana. (U.S. DOE, 2006). New Mexico and Texas indicate that stabilized, uncontaminated solids may be suitable for use as daily cover at landfills. In New York, such waste also appears able to be used as part of the cap but cannot be within 10 ft of the final cover. In Arkansas, Nevada, Oklahoma, Texas and several other states, regulations allow unspecified alternate materials to be used for daily cover (potentially including drill cuttings, produced sand, petroleum-contaminated materials) if the operator shows that the alternative materials can control wastes without presenting a threat to public health and safety and the environment. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-19 6.3.7. Land Application Land application consists of applying waste to the land surface as a means of treatment and disposal. More than half of the states in this review (17 of 28) address land application of E&P wastes through regulations. Nearly all these states (15 of 17) provide specific limitations or conditions for application, which may include waste characteristics, site conditions and operational requirements. A number of states have regulations for land application of septic sludges and other industrial byproducts, but the regulations were not incorporated into the current review. For these remaining states, it is unclear if land application of E&P wastes is prohibited. Waste Types: The types of E&P waste that may be land applied vary by state. Some states allow more than one type of waste to be land applied. Table 6-7 provides examples of the different types of waste allowed for land application in each state. Table 6-7. Summary of Wastes Allowed for Land Application. Waste Type States Water-Based Drilling Fluids and/or Cuttings Oily Waste Including Materials Containing Crude Oil, Condensate or Wastes that Contain Hydrocarbons (Such as Soil, Frac Sand, Drilling Fluids, Drill Cuttings and Pit Sludge) Drilling Fluids, Produced Water and Produced Water-Contaminated Soils, Waste Crude Oil, Sludges, and Oil-Contaminated Soils Drilling and Production Fluids Special Waste Defined as “Gas and Oil Drilling Muds, and Oil Production Brines” Crude Oil Bottom Sediments Naturally Occuring Radioactive Material (NORM) AR, CO, IN, KS, OK, PA, TX CO, NM, OK, PA, U WY VA KY IL, IN MS, TX Permits: There is a wide range of permit requirements for land application amongst the 17 states. Six clearly require permits (i.e., Arkansas, Indiana, Oklahoma, Pennsylvania, Texas, Wyoming). Two either do not require them (Colorado) or only require under certain conditions (Virginia19). Six do not mention permits for land application in state regulations (i.e., Illinois, Kansas, Kentucky, Mississippi, New Mexico, Utah). Of the six states that require permits, Indiana and Texas only require permits for off-lease application of E&P wastes. In Wyoming, permits are issued by the Department of Environmental Quality. Waste Testing: Almost all of states that allow land application (16 of 17) include some limits or conditions for land application of the waste, though the level of detail varies. Some states provide numerical requirements for land application. Various examples from both Indiana and Virginia include: TDS < 1,500 mg/L, Cl < 1,000 or 5,000 mg/L, Fe < 7 mg/L, Mn < 4 mg/L, Oil and Grease < 15 mg/L, pH: 6-9. Some states place restrictions on physical properties, such as the presence of a visible sheen or free water. Other states (e.g., Texas) specify the limits for the soil after application, such as 226+228Ra < 30 pCi/g or < 150 pCi/g of any other radionuclide. Location Restrictions: Most states (14 of 17) have some application site restrictions provided in the regulations. Some of those states only allow land application of wastes on lease property, the site of 19) According to the disposal application form, if TDS exceeds 5,000 mg/kg a permit may be required by VA DEQ. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-20 origin, or “lands previously disturbed by well site construction and drilling operations.” Colorado allows for land application onsite or at a centralized waste management facility. Oklahoma and Texas provide specifications for commercial soil farming facilities; some of which are different from or add to those for non-commercial sites. For instance, in Oklahoma, commercial soil farming facilities have setbacks for incorporated municipalities: 3 miles for populations 20,000 or less, or 5 miles if greater than 20,000. A majority of the 14 states also provide operational conditions for land application. Wyoming and Kentucky do not provide specifications in their regulations, while Arkansas includes criteria in a permit. Some states provide buffer zones/setback restrictions for the application site, including distances from surface water bodies and site boundaries, as well as conditions for the site, such as depth to groundwater and soil types. Table 6-8 provides a summary of the location and siting restrictions for land application of E&P wastes. Location Restrictions Table 6-8. Location and Siting Restrictions for Land Application. Siting Restrictions IN KS Surface Water Body X Water Supply Site Boundary OK PA TX X X X X X X X X X X X X X X UT X VA X Highways X Rock Outcrops, Sinkholes X Building X Pipeline X X X Drainage X Depth to Bedrock Site Conditions NM X X X X Depth to Groundwater X X X Soil Type X X X X Hydraulic Conductivity X Slope X Chloride (in Soil) X Previous Land Application X Chloride (in Groundwater) X Salinity X X X X Examples of weather-related restrictions include prohibiting land application during precipitation events or when ground is frozen or snow-covered. Loading rates are provided for nine states and may include general performance criteria (will not result in runoff or pooling) or values for specific loading rates. The maximum depth of waste applied, and the depth of tilling is specified in nine states. Mississippi required tilling waste into the soil only if precipitation exceeds 25 inches per year. Three states provide regulation on how the waste is to be applied to the soil including the use of injection, pressurized diffusers, disking, or tilling methods and prohibition on gravity feeders, and use of bulldozers and backhoes for incorporating cuttings into soil. Table 6-9 provides a summary of the operational conditions for land application in specific states. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-21 Table 6-9. Summary of Operational Conditions Required for Land Application. Operational Conditions/Criteria Specific States Resulting Concentration in Soil CO, MS, TX, UT Weather-Related Application Restrictions IN, KS, OK, PA, VA Rates to Prevent Runoff, Ponding, Erosion CO, IN, KS, NM, PA, UT, VA Depth of Incorporation IL, MS, PA Maximum Application Thickness CO, KS, NM, OK, TX, UT Enhance Bioremediation CO (oily waste), NM Timeframe for Application CO, KS, NM, UT (Hours/Day after Received) IN (Only Daylight Hours) Loading Rate NM, OK, PA Specific Method of Application (Type, Vehicle, etc.) IL, OK, UT 6.3.8. Beneficial Use EPA defines beneficial use to be the substitution of non-hazardous industrial secondary materials, either as generated or following additional processing, for some or all of the virgin, raw materials in a natural or commercial product (“analogous product”) in a way that provides a functional benefit, meets product specifications, and does not pose concerns to human health or the environment” (U.S. EPA, 2016c). State agencies have the primary authority to determine whether beneficial use of a nonhazardous material is allowed within the state and may use definitions that differ from EPA. For example, some states may classify the processing of waste for oil recovery to be beneficial use. A survey of state management practices for E&P wastes in 2013 included questions about beneficial use (ASTSWMO, 2015). A total of 11 states indicated that they had approved various beneficial uses for drill cuttings (concrete, road base, grading), drilling fluid (concrete), sludge (road application), produced water (dust suppressant, de-icing agent) and other wastes. There is little information available about the frequency of different uses or the volumes of waste involved. However, states have developed requirements for certain beneficial uses of E&P wastes. Types of Waste: Eleven of the 28 states included in this review have requirements that address beneficial use of E&P wastes. Seven states have requirements incorporated into regulations, three provide guidelines (i.e., Alaska, Pennsylvania, Texas), and one outlines requirements in an agreement between the state Division of Highways and Department of Environmental Protection (i.e., West Virginia). The most common use is road application of E&P waste fluids to control dust, stabilize unpaved surfaces, and de-ice road surfaces. Table 6-10 provides a summary of the uses allowed for each type of waste in these states. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-22 Table 6-10. Summary of Waste Types Allowed for Beneficial Use. Type of Waste for Beneficial Use Type of Beneficial Use State Fluid Sludge/Sediment/Solids AK None Drill Cuttings AR None Crude Oil Tank/Pit Solids CO Produced Waters (Flowback Fluids Prohibited) None Dust Control (Lease Roads) LA Brine None Roadspreading, Deicing MI Brine None Dust and Ice Control, Road Stabilization NY Brine (Flowback and Marcellus Shale Water are Prohibited) None Dust Control, Unpaved Road Stabilization, Ice/Snow Reduction OH Brine (Horizontal Wells Prohibited) None Dust and Ice Control PA Production or Treated Brine (Not from Shale Formation) None Dust Control, Road Stabilization TX Treated Fluid Oily Waste Waste Solids WV Brine None WY Drilling Fluids, Produced Water Construction of Roads, Pads and Berms on Oil and Gas Properties Owned or Operated by the Company Oiling (Lease Roads) Treated Fluid: Any Approved Re-Use That is Not Considered Disposal Oily Waste: Roads (Lease or County), Firewalls Other Waste Solids: Concrete Bulking Agents, Landfill Cover or Capping Material, Landfill Berms, Construction Fill Material or Treated Aggregate, Closure or Backfill Material, Firewall, or Other Construction Fill Material Prewetting, Anti-Icing, Deicing Produced Water-Contaminated Soils, Waste Crude Oil, Sludge, Roadspreading, Road Application Oil-Contaminated Soils Testing Requirements: These 11 states include a wide range of requirements for waste characteristics and operational conditions. Wyoming requires slightly different analyses for particular waste types. Table 6-11 provides a summary of common testing requirements for beneficial uses in select states. Additional analyses may be required by certain states. Colorado requires sampling of soil adjacent to road application and includes a list of 18 organic compounds and three additional parameters (electrical conductivity, sodium adsorption ratio and pH). Texas requires testing of one sample from each 200 cubic yards of treated products. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-23 Table 6-11. Summary of Beneficial Use Testing Requirements. WY Parameter AK TPH AR CO MI NY X TDS TX WV X X X SO4 X Drilling Fluid and Cuttings PetroleumContaminated Soil Produced Water and Contaminated Soil X X X X X X H2S X Cl X Ca X Na, Fe Ba, Pb X Ag, As, Cd, Cr, Hg, Se X X X X X X X X X X X X X X X Ra-226 X X X Oil/Grease X X Benzene X X Toluene X X X Ethylbenzene X X X Xylene X X X TOX X X X X X X X X TOX – Total Halogenated Organics Limitations on Use: States also provide specific restrictions for the site of use, such as distance from surface water body and grade of the roadway. Some provide more general description for the site. For example, Colorado regulations state that roadspreading may be conducted on lease roads outside “sensitive areas.” Six of the 10 states also provide operational conditions for beneficial use. New York and Pennsylvania specify setbacks from surface water bodies of 50 and 150 feet, respectively. In New York and Pennsylvania (when brine is used for dust control or road stabilization), a maximum roadway grade of 10 percent is allowed and brine may not be applied to wet roads during rain or when rain is imminent. Brine may not be applied between sundown and sunrise, except for ice control in Ohio and when applied for dust control/road stabilization in New York. Michigan, Texas and Wyoming do not include such requirements in their regulations. Application rates for natural gas brines in West Virginia are “limited to 10 gallons per ton for prewetting use, 50 gallons per lane mile for anti-icing use, and 100 gallons per lane mile for de-icing use.” Ohio regulations state “the maximum uniform application rate of brine shall be 3,000 gallons per mile on a 12-foot-wide road or 3 gallons per 60 square feet on unpaved lots.” Pennsylvania regulations indicate “The road should initially be spread at a rate of up to one-half gallon per square yard (typically after the road has been graded in the spring). The road should subsequently be spread at a rate of up to one-third gallon per square yard no more than once per month unless–based on weather conditions, traffic volume or brine characteristics–a greater frequency is needed to control dust and stabilize the Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-24 road. The application rate for race tracks and mining haul roads should be determined for each site and should not exceed one gallon per square yard.” New York regulations do not provide a numerical value but state that “the brine application must not be used at a rate greater than needed for snow and ice control.” Vehicle requirements are provided for three states. In Pennsylvania, “brine must be spread by use of a spreader bar with shut-off controls in the cab of the truck…and each vehicle used to spread brine shall have a clearly legible sign identifying the applicator on both sides of the vehicle.” Ohio regulations specify “the discharge of brine through the spreader bar shall stop when the application stops…the applicator vehicle shall be moving at least five miles per hour at all times while the brine is being applied…The maximum spreader bar nozzle opening shall be three-quarters of an inch in diameter…the angle of discharge from the applicator vehicle spreader bar shall not be greater than sixty degrees from the perpendicular to the unpaved surface…only the last twenty-five per cent of an applicator vehicle's contents shall be allowed to have a pressure greater than atmospheric pressure; therefore, the first seventy-five per cent of the applicator vehicle's contents shall be discharged under atmospheric pressure.” When brine is used for dust control or road stabilization in New York, “a spreader bar or similar device designed to deliver a uniform application of brine must be used; the application vehicle must have brine shut-off controls in the cab…when the application vehicle stops, the discharge of brine must stop; and the vehicle must be moving at least five miles per hour when brine is being applied.” Some states provide additional details in their regulations. Arkansas, for instance, states “immediately following completion of the application, all liquid fractions shall be immediately incorporated into the road bed with no visible free-standing oil; and no lease road shall be oiled more than twice a year.” In Michigan, the well owner may not use brine for beneficial use but may convey or transfer it for use by another party. In addition, the administrative requirements for beneficial use of E&P waste vary amongst the states reviewed. For example, Ohio requires a permit, Texas requires a permit for off-lease only, New York requires a written petition, and Kansas requires an application. Ohio also provides detailed information about the approval process, and the Texas permit application provides detailed requirements for treating and recycling oil and gas solid waste for commercial or industrial use. Table 6-12 provides a summary of common restrictions on the placement of brine and other waste liquids on roadways. Table 6-12. Summary of Restrictions on Placement of Waste Liquids on Roadways. Site Restrictions Site and Operational Restrictions Specific States Distances to Surface Water Bodies NY, PA Grade NY, PA Within 12ft of Structures Crossing Water Bodies or Crossing Drainage Ditches NY, OH Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-25 Table 6-12. Summary of Restrictions on Placement of Waste Liquids on Roadways. Operational Restrictions Site and Operational Restrictions 6.3.9. Specific States Weather-Related (Flooded, Snow Covered, Frozen Ground) NY, PA Prevent Pooling/Runoff, Impact to Surface Water Bodies AR, CO, PA Time of Day NY, OH (except for ice control) Specific Loading Rate NY, OH, PA, WV Vehicle Requirements NY, OH, PA Avoid Vegetation NY, OH NORM and TENORM The wastes generated during drilling, completion, production, workover and closure may contain elevated concentrations of certain radioactive elements (“radionuclides” or “radioisotopes”). EPA uses the general term “technologically enhanced radioactive materials (TENORM)” to refer to these wastes. EPA defines TENORM as "naturally occurring radioactive materials that have been concentrated or exposed to the accessible environment as a result of human activities such as manufacturing, mineral extraction, or water processing. Technologically enhanced means that the radiological, physical, and chemical properties of the radioactive material have been altered by having been processed, or beneficiated, or disturbed in a way that increases the potential for human and/or environmental exposures.” State regulations use terminology that includes TENORM, NORM, and naturally occurring and/or accelerator-produced radioactive material (NARM). There can be important distinctions between these different terms, as some states specifically exclude wastes classified as NORM from state radiation regulations. The current discussion uses TENORM for all wastes that have the potential to have elevated activity, unless referring to the regulations of a specific state. Table 6-13 provides a summary of the different terminology typically used by different states in regulatory text. Table 6-13. Summary of Terminology for Radioactivity Terminology Specific State NORM AR, IL, IN, MS, NM, TX, WY TENORM KY, MT, ND, NY, VA, WV NARM FL, NY, NV, TN NORM and TENORM CO, ID, OH, PA Naturally Occurring Material MI Radiation Regulations: Most of the states reviewed (22 of 28) address radioactivity somewhere in the state regulations. Only ten states discuss radioactivity within the E&P regulations, though some (e.g., Tennessee) simply refer back to the state’s radiation regulations. Of the top five producing states (i.e., Texas, Pennsylvania, Alaska, Oklahoma, North Dakota), Texas and North Dakota have the most extensive regulations. Pennsylvania requires a comprehensive radioactive material action plan for any onsite treatment of fluids or drill cuttings. Alaska and Oklahoma do not specifically address this topic. In nearly all of the states, primary responsibility for regulating TENORM lies with the state health Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-26 department (ten states) or environmental agency (includes solid waste agencies). For example, radioactivity in New Mexico is regulated by the Oil and Gas Conservation Division, and Texas is regulated primarily by the Railroad Commission and supported by the Department of State Health Services. Texas regulations include a clear and comprehensive description of the jurisdiction of the two agencies. The delineation of roles is less clear in the regulations of other states with split jurisdiction, though several states (e.g., Colorado, North Dakota) provide fact sheets to help operators navigate the regulations. Because of the fragmented nature of E&P regulations on radioactivity, it was challenging to construct a complete picture of the coverage of all aspects of regulation across the country. EPA found that state regulations touch on a wide range of issues including planning requirements, operational activities at the well or production site, closure activities, or characterization and disposal (includes onsite, downhole and offsite landfills). However, few states cover all these areas and the relevant regulations are often scattered across different agencies and sections of regulatory text. The most comprehensive regulations related to solid waste landfill requirements and downhole well disposal. A few states addressed radioactivity associated with waste management unit operation and closure. Action/Management Plan: Four states (i.e., Illinois, Indiana, Louisiana, New Mexico) require an action/management plan to manage radioactivity, but the required content varies. For instance, in Illinois, E&P waste is considered low-level radioactive waste and disposal is managed under the Central Midwest Interstate Low-Level Radioactive Waste Commission Regional Management Plan, but a sitespecific action plan addressing handling and testing of E&P waste is required as part of the Illinois oil and gas permitting regulations. The Action Plan required in Pennsylvania, however, is specific to oil and gas operations and must include procedures for monitoring and responding to radioactive materials produced by the treatment process and procedures for training, notification, recordkeeping and reporting. Some states appear to require action or management plans as part of the radiation safety protection regulations (under the public health division or solid waste division) but it is often unclear how or if these regulations apply to operation and disposal at oil and gas operations. Storage Requirements: Eight states include some type of storage requirements for NORM/TENORM wastes. For example, North Dakota provides detailed requirements for management and inspection of containers and tanks containing TENORM waste. Wyoming guidelines indicate NORM wastes “should be stored in enclosed containers, durable synthetic fiber ‘super sacks’ or equivalent” for periods not to exceed 90 days, 180 days or up to 1 year depending on the activity and volume of the waste. In addition, West Virginia requires an annual registration form and Arkansas refers to general “NORM radiation requirements” for storage. Disposal Screening: Eleven states require screening for radioactivity prior to disposal either onsite or at the landfill. Although many regulations do not provide detailed requirements for testing, New York includes a specific regulation for screening when cuttings with NORM/TENORM are disposed. Pennsylvania requires radiation testing for disposal at offsite municipal landfills but not for NORM/TENORM wastes specifically. While Colorado does not require screening at the landfill prior Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-27 to disposal, testing of each waste shipment by the facility generating the waste is required prior to transport. Illinois and several other states require testing of soil and residues before pit closure. Sitespecific landfill permits may include requirements for screening of incoming materials for radioactive materials or provide specific acceptance criteria. Disposal Options: Most states (23 of 28) discuss disposal options for these wastes, which may vary depending on waste activity. The most common option is offsite disposal at facilities permitted for general radioactive waste or more specific NORM/TENORM. Disposal at solid waste or hazardous waste facilities is allowed in some states in accordance with specific thresholds. Other options include downhole injection, land spreading, onsite burial and reuse. Some states may allow more than one type of disposal. Ohio regulations, for instance, state “lawful disposal” of wastes is required, which may include reuse, injection and out-of-state disposal. Florida regulations are complex but appear to allow NORM/TENORM disposal by a variety of methods. Administrative requirements such as notification, reporting and permitting also vary by state. For example, Indiana regulations require notification and a disposal plan but not a permit for NORM disposal. Permits are required for disposal in some states, such as Mississippi and New York. In New York, no permit is required for disposal of NORM but disposal of TENORM is highly restrictive. States governed by interstate agreements or compacts for low-level radioactive waste often include an additional layer of regulations regarding import and export of radioactive materials for disposal. Disposal Limits: Nearly all (20 of 23) states that explicitly allow disposal present activity limits. Based on the regulations reviewed, numerical thresholds typically range from 3 picocuries per gram (pCi/g) of 226+228Ra (Colorado) to 200 pCi/g 226+228Ra (Kentucky). In many states, wastes classified as NORM are exempt from regulations if the materials contain concentrations less than 5 pCi/g of 226+228Ra or 100 pCi/g of other naturally occuring radionuclides. Colorado currently has three landfills permitted for TENORM disposal with different acceptance criteria, while solid waste facilities may be used only if stringent testing and radioactivity criteria are met. The type of facility where disposal is allowed may depend on the waste activity. Wyoming regulations allow disposal at a solid waste facility for waste up to 50 pCi/g 226Ra while wastes with levels greater than 50 pCi/g 226Ra must be managed at out-of-state facilities authorized to accept low-level radioactive waste. In Michigan, disposal of waste up to 50 pCi/g 226Ra is allowed in a hazardous waste or Type 2 landfill, but wastes greater than 50 pCi/g 226Ra must be disposed in a licensed radioactive waste facility. No limits are presented for downhole disposal of waste. Conclusions The review of state regulatory programs focused on 61 specific elements organized into 12 general topic areas. Each of these elements (e.g., location restrictions, inspections) was chosen based on a review of existing federal solid waste management programs. The selected elements are those that EPA considers to be broadly applicable, regardless of waste type, and so provide a reasonable basis for comparison among different programs. Yet the absence of a particular element in this review does not necessarily Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-28 mean a state program is deficient. Some states may not address a particular practice in regulations because issues are handled on a case-by-case basis (e.g., beneficial use) or the practice is does not occur within the state boundaries (e.g., centralized pits). In some cases, professional judgment was required to interpret how regulatory language would be implemented by the relevant state agencies. It is possible that separate guidance documents and individual permits further elaborate on requirements in the regulatory text; however, these documents may not be posted publicly or may require foreknowledge of specific wells or management units to locate. Therefore, this regulatory review, while not fully comprehensive, does provide a great deal of information about the scope of coverage (e.g., the wastes and activities), and the level of detail and precision in the requirements to determine where these programs are equivalent to or expand upon current RCRA Subtitle D requirements. EPA reviewed the text of regulations from 28 of the 34 states with reported production of oil and gas tracked by the EIA. Together, these states represent over 99% of the total oil and gas production in the United States. Table 6-14 provides a summary of the states reviewed, organized by the estimated percent of national crude oil and natural gas production in 2016 (by volume expressed in barrels). Table 6-14. Ranking of State Oil and Gas Production Percent Production State Percent Production State Percent Production State Percent Production State 32.0% Texas 4.6% New Mexico 1.0% Kansas 0.04% Indiana 11.5% Pennsylvania 4.4% Louisiana 0.4% Montana 0.04% New York 8.4% Alaska 3.4% Ohio 0.4% Mississippi 0.03% Florida 7.3% Oklahoma 3.1% West Virginia 0.3% Michigan 0.01% Idaho 6.0% North Dakota 2.8% California 0.3% Virginia 0.01% Tenessee 5.1% Colorado 1.8% Arkansas 0.2% Kentucky 0.01% Nevada 4.9% Wyoming 1.2% Utah 0.1% Illinois 0.01% Missouri Generally, EPA found that state regulatory programs for E&P waste include a majority of the elements relevant to the management of solid wastes. The scope and specificity of regulatory programs varied among states; however, some general trends were observed relative to the amount of oil and gas production in the states. The 11 highest-producing states account for more than 90% of national production. These states tend to have regulatory programs tailored specifically to the management of E&P wastes, which can include specific requirements by well type (e.g., conventional, unconventional), waste type or management practice. These states are also more likely to have centralized infrastructure dedicated to the storage and disposal of E&P wastes mainly due to the sheer volume of waste generated and the possibility of overwhelming the capacity of other disposal options (e.g., municipal solid waste landfill). The remaining 17 states account for around 9% of total oil and gas production. It appears that these states tend to have more general programs that address E&P waste management under the same or similar regulatory framework as other non-hazardous solid wastes. These states are more likely to manage E&P wastes, as appropriate, within existing landfills and may not have requirements that specifically reference E&P wastes. Table 6-15 provides a summary of the prevalence of each element in state programs based on Agency review. Each specific regulatory elements within a topic area is ordered from greatest to least coverage. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-29 Table 6-15. Summary of State Program Regulatory Elements General Topic 1 Specific Element Consistency with 40 CFR Part 257.3 – Coverage 1) Groundwater 2) Surface Water 3) Floodplains 4) Endangered Species Percent of National Production State Count 94% 94% 93% 31% 25 24 23 9 Waste Management Location Requirements (Siting and Setbacks) 2 3 4 5) Environmental Receptors (Surface Water, Wetlands, Watercourses) 91% 22 6) Residential 73% 17 7) Depth to Groundwater 42% 13 Tank Requirements (Onsite/On-Lease) 8) Tank Berms and Containment Specifications 9) Requirements for Tank Construction Material 10) Tank Bottom Removal Permit Required 11) Netting for Open Tanks Required 12) Requirements for Modular Large Volume Tanks 13) Tank Monitoring Required 74% 50% 50% 46% 18% 12% 18 11 4 7 2 4 Pit Construction and Operation Requirements 14) Requirements for Pit Liners 99% 27 15) Multiple Pit Content/Use Types Specified 88% 23 16) Temporary Pit Requirements 88% 17 17) Requirements for Fencing 87% 18 18) Freeboard Requirements 86% 20 19) Berm Requirements 84% 17 20) 21) 22) 23) 24) 25) 26) 27) 28) 29) 30) 31) 81% 80% 74% 72% 70% 69% 62% 57% 55% 40% 37% 27% 15 19 11 11 16 13 5 11 10 12 6 7 32) Liquids Removal Required 87% 23 33) Closure Schedule Specified 85% 22 34) Inspections Required 71% 10 35) Solids Removal Required 64% 17 36) Sampling Required 55% 8 37) Financial Security Required 3% 1 GW Monitoring Required Run-On and Run-Off Controls Inspections Discharge Permits Required Permit Required Prohibited Pits Non-Commercial Fluid Recycling Pits Netting Leak Detection/Monitoring Required Depth to Groundwater Specified (Minimum) Centralized Pits Pit Signage Pit Closure Requirements 5 Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-30 Table 6-15. Summary of State Program Regulatory Elements Percent of National Production State Count 38) Spill Notification Required 91% 26 39) Corrective Action Plan Required 78% 20 40) E&P Waste Allowed in Offsite Landfills 99% 25 41) Testing of Waste Required 51% 7 42) Use of E&P Wastes as Daily Cover Allowed 7% 2 81% 17 General Topic Specific Element Spill Notification and Corrective Action 6 Offsite Landfills 7 Land Application 8 9 43) Land Application Allowed 44) Specific Limitations/Conditions for Land Application 79% 16 45) Location Restrictions 69% 14 68% 11 47) Testing Requirements for Beneficial Use 64% 10 48) Specific Limitations/Conditions for Road Spreading 62% 9 49) Closed Loop Drilling Requirements 25% 7 50) Produced Water Recycling Requirements 0% 0 51) Commercial Facilities Regulated (Specify if Permit is Required) 58% 7 52) Financial Security/Closure Required 50% 4 53) Offsite Reclamation Manifest Required 50% 4 54) Monitoring and Testing Required During Operation 50% 4 Beneficial Use 46) Road Spreading Allowed (Specify if Permit is Required) Waste Minimization and Best Management Practices 10 Commercial On/Off Lease and Stationary Recycling/Reclamation Facilities 11 NORM and TENORM 55) State Regulations Address Radioactivity 12 79% 22 56) Disposal Allowed 71% 23 57) Disposal Limitations and Conditions 67% 20 58) Onsite or Landfill Testing/Screening Required 60% 11 59) E&P Waste Regulations Address Radioactivity 47% 8 60) Storage Requirements 28% 8 61) Action Plan/Management Plan Required 9% 4 The level of coverage for each element is variable. This is expected, as the scope and specificity of state programs can vary in response to regional factors that impact the types of waste generated and the appropriate methods to manage those wastes. However, several elements are present in regulations for nearly every state reviewed. Many of these elements are more standardized requirements intended to either prevent releases to the environment (e.g., pit liners) or ensure that releases are identified and addressed (e.g., spill reporting, groundwater monitoring). Other elements have substantial coverage, but from a relatively small number of states, which indicates these elements (e.g., centralized disposal) are concentrated states with higher production. The elements with the lowest coverage (e.g., tank signage, financial assurance, produced water recycling) tend to be those that do not directly address Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-31 potential environmental releases, but are considered best management practices. There is no indication from this review that there are widespread gaps in the scope of the written regulations. Any gaps that are identified for individual states might be better addressed through outreach and other targeted actions. States have continued to periodically update regulatory programs that address issues raised by increased production, emerging environmental issues, and ongoing reviews from third parties. At least 24 states out of the 28 reviewed have revised their regulations related to E&P wastes in the past six years, with some revisions as recent as 2018. Table 6-16 provides a summary of the most recent updates for each state. Table 6-16. Most Recent Updates to State Programs State Percentage of Production Most Recent Updates Identified Texas Pennsylvania Alaska Oklahoma North Dakota Colorado Wyoming New Mexico Louisiana Ohio West Virginia California Arkansas Utah Kansas Montana Mississippi Michigan Virginia Kentucky Illinois Indiana Florida New York Idaho Tenessee Nevada Missouri 32.0% 11.5% 8.4% 7.3% 6.0% 5.1% 4.9% 4.6% 4.4% 3.4% 3.1% 2.8% 1.8% 1.2% 1.0% 0.4% 0.4% 0.3% 0.3% 0.2% 0.1% 0.04% 0.03% 0.04% 0.01% 0.01% 0.01% 0.01% 2013 2016 2017 2017 2015 2016 2016 2016 2014 2005 2016 2015 2012 2016 2013 2018 2015 2015 2016 2007 2014 2017 2013 Unknown 2015 2013 2014 2016 Based on this review, EPA concludes that the scope and specificity of regulatory programs varies among the states based on a number of factors, such as the quantity of oil and gas produced in the state and the prevalence of hydraulically fractured wells. Despite this variability, the existing state programs incorporate a majority of elements found in federal waste management programs, which indicates that Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-32 the scope of the written state regulations is robust. However, the way in which these regulations are interpreted and implemented are also important considerations. To better understand which practices may pose concern, EPA reviewed the assembled literature for existing evaluations that had drawn conclusions about the potential for adverse effects from management of E&P wastes. Management of Oil and Gas Exploration, Development and Production Wastes Section 6: State Programs 6-33 7. Review of Existing Evaluations EPA reviewed the available literature to identify evaluations that had previously quantified the risk of adverse effects associated with the management of E&P wastes. The purpose of this review was to determine whether the data and analyses that underpin the findings of these evaluations are of sufficient quality to draw conclusions about the current management practices. EPA identified two evaluations that provide quantitative estimates of potential risk:  Technical Support Document Onshore Oil and Gas Exploration, Development, and Production: Human Health and Environmental Risk Assessment (U.S. EPA, 1987d)  Potential Radiological Doses Associated with the Disposal of Petroleum Industry NORM via Landspreading (U.S. DOE, 1998) EPA reviewed the data relied upon and analyses conducted for these evaluations to identify any major sources of uncertainty. Moreover, EPA considered how the information that has become available since the completion of these evaluations might affect reported risks. Based on this review, EPA determined whether these evaluations support any conclusions about the types of management practices that could result in adverse effects. U.S. Environmental Protection Agency (1987d) In the 1987 Technical Support Document Onshore Oil and Gas Exploration, Development, and Production: Human Health and Environmental Risk Assessment (1987 TSD; U.S. EPA, 1987d), EPA evaluated the risks that might result from the management of E&P wastes from exploration and production. The potential release routes examined were leaching from pits with and without liners and caps, inadvertent discharges to groundwater through well failure and direct discharges to surface water from wells. The following discussion focuses only on waste management in pits. Discharges from waste management units to water bodies are classified as point sources and regulated under the Clean Water Act. Disposal through injection wells is regulated under the Safe Drinking Water Act. Therefore, these management practices are not further discussed in the context of RCRA. 7.1.1. Evaluation Summary To characterize wastes generated for the 1987 TSD, EPA initially collected 100 samples of drilling and production waste from 49 sites across the country. Sampling locations included centralized treatment facilities (3 sites), central disposal facilities (4 sites), drilling operations (19 sites), and production facilities (23 sites). EPA analyzed the collected samples for 534 constituents and parameters that included 444 organic compounds, 68 inorganic elements, 19 water quality parameters, and 3 RCRA characteristics.20 EPA initially limited the quantitative evaluation to 36 inorganic elements and 25 organic compounds based on frequency of detection in waste samples and availability of toxicity values. 20) Water quality parameters include pH, total suspended and dissolved solids and biological oxygen demand. RCRA characteristics include corrosivity, ignitability and reactivity. Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-1 This list was then further refined based on anticipated mobility of constituents in groundwater (i.e., likelihood to reach receptors). Constituents ultimately retained for fate and transport modeling included benzene and arsenic for cancer risk; cadmium, chromium and sodium for noncancer risk; and boron, cadmium, chloride, chromium and sodium for aquatic toxicity and environmental resource damage. The 1987 TSD modeled fate and transport from pits. A range of disposal unit sizes and distances to receptors were considered. Risks were found to be below levels of concern for all modeled exposure scenarios. For waste disposed in reserve pits, the majority of modeled cancer risks were less than 1×107 and none were greater than 1×10-5. Only two percent of model runs for unlined pits resulted in noncancer risks from sodium. However, EPA concluded that the high salt content of produced waters would result in noticeable and unpleasant changes to the taste of water concurrent with any elevated risks, which would alert residents and limit exposures. 7.1.2. Uncertainties As with any evaluation, there are uncertainties associated with the 1987 TSD. Some may arise from the practical limitations of models and data available at the time, while others are driven by changes to industry practices in the decades since the evaluation was finalized. The following discussion summarizes key uncertainties identified during this review and, where practicable, how consideration of more recent data might affect the evaluation findings. Waste Types Evaluated The reserve pits modeled in the 1987 TSD contained wastes generated from drilling with water-based fluids. The main types of waste managed in these pits are cuttings and drilling mud. There are a number of other wastes generated during exploration and production (e.g., produced water, sludge) and, as shown in this document, these wastes may contain higher concentrations of some constituents than drilling solids. EPA acknowledged in the 1987 TSD that these other wastes might potentially result in adverse effects to human health and the environment. However, the Agency did not have adequate data at the time on the chemical composition, sources, volumes and management practices for these other waste types to permit evaluation of the associated risks. As a result, no conclusions can be drawn from this evaluation about the risks associated with these additional wastes. Waste Composition The largest shift in drilling practices in the past three decades has been the adoption of directional drilling. Although hydraulic fracturing has been used since the 1950s, the practice was not as widespread until the 2000s when advances in directional drilling allowed greater access to formations that had been previously deemed uneconomical (Soeder et al., 2014). This shift in drilling practices resulted in greater volumes of waste due to the greater distance drilled and the large volume of water needed for fracturing. To better understand the extent to which the composition of these wastes may also have changed since 1987, EPA compared the constituent concentrations used in the 1987 TSD and those assembled in the current E&P database. Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-2 In 1986, EPA was able to sample only a limited number of facilities due to time and resource constraints. To provide a best estimate of typical waste concentrations from these samples, EPA first weighted selection of sample locations based on indicators of waste generation from previous reports. Drilling site selection was weighted based on total wells drilled in each state, while production site selection was weighted based on annual hydrocarbon production in each region. Samples from the north slope of Alaska were omitted from summary statistics because this region was handled in a separate qualitative evaluation. The current produced water dataset is based on a review of available literature and so the Agency did not have any control over the type or number of samples available. This resulted in uneven sampling in different regions of the country. Therefore, EPA weighted the available data by the annual hydrocarbon production in each region of the country. All samples within a given region were given the same weight. Table 7-1 provides a comparison of the 50th and 90th percentile concentrations from vertical wells in the 1987 TSD and horizontal wells in Pennsylvania (the only state with data available) in the current dataset. Table 7-1. Comparison of Constituent Data for Produced Water Constituent 1987 Vertical Data Current Vertical Data Current Horizontal Data N 50th 90th N 50th 90th N 50th 90th Arsenic 9 / 24 0.02 1.7 51 / 65 0.01 0.20 -- -- -- Benzene 16 / 21 0.47 2.9 27 / 32 0.23 4.9 -- -- -- Boron 24 / 24 10 120 1,369 / 1,370 39 115 192 / 195 21 46 Chloride 21 / 21 7,300 35,000 39,766 / 39,766 27,500 132,048 291 / 291 71,200 132,000 Sodium 24 / 24 9,400 67,000 39,138 / 39,138 15,375 62,678 291 / 291 34,700 52,322 N – Detection Frequency The two vertical datasets ostensibly reflect the same waste and so should be similar if all sources of variability have been captured. Both high-end and median concentrations of benzene, boron and sodium are similar and median concentrations of arsenic are similar. The similarities between the two datasets provides some confidence that the overall distributions for these constituents. The greatest difference between the datasets is chloride. It is not clear why chloride in the 1987 TSD is lower than both chloride in the current vertical dataset and sodium in the same dataset. This indicates that the 1987 TSD may underestimate concentrations of certain constituents. The current dataset for drilling fluid was assembled through the same literature review as produced water. However, unlike produced water, there was not sufficient data from across the country to weight the data by region to obtain a more representative national distribution. Instead, EPA conducted a more limited comparison with horizontal data from a single state. Table 7-2 provides a comparison of the 50th and 90th percentile concentrations contained in the 1987 TSD and the current dataset for horizontal wells in Pennsylvania. Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-3 Table 7-2. Comparison of Constituent Data for Drilling Fluid Constituent 1987 Vertical Data Current Horizontal Data N 50th 90th N 50th 90th Arsenic 6 / 17 ND 0.16 12 0.03 0.18 Cadmium 13 / 17 0.04 1.4 -- -- -- Chloride 17 / 17 3,500 39,000 35 17,000 89,000 Chromium 14 / 17 0.43 290 13 / 21 0.25 1.3 Sodium 17 / 17 6,700 44,000 33 11,400 33,900 N – Detection Frequency ND – Non-Detect Some of the trends observed for produced water are also present in the data for drilling fluid. Both high-end and median concentrations of arsenic and sodium are similar, while chloride concentrations in the 1987 TSD are lower than both the current dataset and sodium in the same dataset. Chromium is substantially higher in the 1987 TSD, which might be attributed to the additive chrome lignosulfonate that was historically used to deflocculate clay particles and to reduce fluid viscosity (NRC, 1983). There are reports that this additive is used less frequently in current drilling operations and is often replaced by iron or calcium lignosulfonate (Schlumberger, 2018). However, to the extent the chromium-based additive is still used, the current dataset may underestimate chromium concentrations. Based on this comparison of datasets, EPA concludes there is general agreement between the two datasets for several constituents. Other constituents were found to be higher or lower in the 1987 TSD, though there is no evidence of a consistent bias in either direction. The greatest difference between the datasets is for chloride. It might be possible that lower chloride levels in the 1987 TSD are the result of analytical error due to improper calibration for high concentrations. There is not enough data available to determine whether other constituents that have a strong relationship with chloride (e.g., strontium) are also lower in this dataset. This remains a source of uncertainty. Additional Constituents The 1987 TSD analyzed for 444 organic compounds. A majority of these compounds were not detected in any samples. However, some were later detected at low concentrations in more recent studies. It is possible that the 1987 TSD failed to identify some compounds present because of higher detection limits. It is also possible that some of these compounds were not present in 1987 and were introduced into recent samples by hydraulic fracturing additives. Between 1,400 to 2,500 compounds have been tentatively reported in samples of produced water by different studies. Some of the compounds detected in recent studies were not analyzed for in the 1987 TSD. Therefore, there is potential for additional risks from additives that were not considered in the 1987 TSD. The 1987 TSD did not address radiation from E&P wastes. Public health concerns were initially raised when pipe scale with high activity was identified in drilling equipment around the Gulf Coast (API, 1989). EPA began efforts to characterize the occurrence and potential impacts of NORM and TENORM in the late 1980s (U.S. EPA, 1993). A draft report was reviewed by the EPA Science Advisory Board (U.S. EPA, 1994), but was not finalized based on the need for additional data to address remaining Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-4 uncertainties. Around the same time, several states began to collect data on radioactivity in E&P wastes (e.g., WVDEQ, 1990; MIDNR/DPH, 1991; TXBEG, 1995; CADHS/DC, 1996; NYDEC, 1999). To assist states with the management of these and other TENORM wastes, the Conference of Radiation Control Program Directors developed suggested regulations (Part N) that address a structure for licensing programs, worker protection, release limits and conditions for regulatory exemption. These suggestions have been revised and updated on an ongoing basis, most recently in 2004. A number of states have incorporated these suggestions into regulatory programs for E&P wastes (ASTSWMO, 2015). Further discussion of state regulations is provided in Section 6 (State Programs). However, renewed concerns have recently arisen due to the expansion of directional drilling (e.g., U.S. DOE, 2014; WVDEP, 2015; PADEP, 2016). Both the increased waste volume and the potential for higher activities pose additional management challenges. To understand whether and how recent changes in drilling practices might affect the composition of E&P waste, EPA compiled data on radioisotope activities in the E&P Database. The available data indicate that elevated activities of uranium or radium can be present in waste from both vertical and horizontal wells. These elevated activities are not isolated to specific formations and, thus, are likely to have been present at similar levels in samples analyzed for the 1987 TSD. Model Duration The 1987 TSD refined the ultimate list of constituents evaluated based on mobility in the environment, focusing on those anticipated to reach receptor wells within 200 years of the initial release. Wells were assumed to be present at distances of 60, 200, and 1,000 meters away from waste pits. This constraint resulted from limitations in the Landfill Liner Model. More recent model runs with the EPA Composite Model for Leachate Migration with Transformation Products on coal ash ponds found that that median time for peak concentrations of arsenic to reach the nearest wells at similar distances ranged from 2,000 to 10,000 years, depending on chemical speciation (U.S. EPA, 2014d). The results of this risk assessment cannot be directly transposed onto E&P wastes. However, it is clear that the 200-year limit is likely to underestimate potential long-term risks. Constituent Mobility Partitioning coefficients (Kd) are ratios of constituent mass that is bound to the soil and dissolved in the aqueous phase at equilibrium. Higher values reflect greater retention on the soil and lower mobility through the subsurface. In the 1987 TSD, EPA reviewed the available literature to identify values for each modeled constituent and selected single values intended to be representative for each constituent. However, partitioning coefficients can be affected by a number of environmental factors that are not constant. Some key factors known to affect Kd values include the concentration of the constituent in groundwater, the pH and ionic strength of the solution, the degree of soil saturation, and the type and amount of different sorbents present within the aquifer. EPA developed the Metal Speciation Equilibrium for Surface and Ground Water Model in 1999 to calculate Kd values for a wider range of environmental conditions and provide a better estimate of constituent mobility for different types of waste (U.S. EPA, 1999a). The most recent version of this model was released in 2006 (Version 4.03). To understand the extent to which single Kd values may overestimate or underestimate constituent mobility, EPA compared values used in the 1987 TSD with Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-5 those calculated for municipal solid waste landfills (U.S. EPA, 1999b) and coal combustion residual (CCR) landfills (U.S. EPA, 2014d). These calculated values incorporate variability from different aquifer pH, ionic strength, organic matter and iron oxide sorbents. Because these values can vary widely on a national-scale, EPA selected high and low bounds for comparison. Table 7-3 presents the result of this comparison. It is anticipated that E&P wastes will most closely resemble CCR data because of the similarly high ionic strength of the wastes. Table 7-3. Comparison of Saturated Zone Partitioning Coefficients (ml/g) Constituent Arsenic (III) Arsenic (V) Boron Cadmium 1987 TSD Unsaturated Saturated Unsaturated Saturated Unsaturated Saturated Unsaturated Saturated 5.0 5.0 3.0 6.5 Municipal Solid Waste CCR Waste Landfill Low High Low High 5×10-3 3.0 9×10-8 0.64 -3 3.0 -7 2×10 0.2 10,000 1.9 0.6 10,000 1.0 -- -- -- -- 0.1 10 0.1 3.0 1.1 5×10 1,100 450 -10 0.80 < 1×10 -6 1×10 3×10-5 -10 < 1×10 0.2 2.3 7.3 -- Constituent not modeled In several cases, the entire range of modeled Kd values are lower than the individual value used in the 1987 TSD, often by several orders of magnitude. The major exception is arsenic (V), which ranges from slightly lower to several orders of magnitude higher. Based on this comparison, the groundwater model in the 1987 TSD will tend to underestimates the potential mobility of the modeled constituents. 7.1.3. Findings U.S. EPA (1987d) found limited potential for risk from disposal of drilling solids in pits. However, there are several uncertainties associated with the analysis conducted that may, on the whole, result in an underestimation of risk. The greatest uncertainties are waste types, management practices, constituents and release pathways that could not be evaluated due to a lack of data. The extent to which the analysis might underestimate actual risks is not clear and EPA did not attempt to update the model results as part of this review. A number of states now have regulations in place that require use of liners and other controls for pits that would potentially mitigate releases from these wastes. Therefore, there is not enough information available from this existing evaluation to draw conclusions about the current disposal practices for E&P wastes. U.S. Department of Energy (1998) In 1998, the U.S. DOE Argonne National Lab modeled exposures that may result from land application of E&P wastes that contain TENORM. This report expands on previous analyses reported in Smith et al. (1995). The practice of disposing of E&P waste in surface soil has been referred to by various terms that describe a range of practices with substantial overlap (e.g., landspreading, landfarming, land application, land treatment). These practices may involve spreading waste on top of the soil or mixing Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-6 it into the soil column. Application of the waste may occur all at once or in multiple iterations. The primary goal of these disposal practices is the natural attenuation of organic compounds combined with the dilution and immobilization of other contaminants. To this end, nutrients or other soil amendments may be spread along with the waste to promote degradation of organics and the soil may be periodically tilled to improve aeration (API, 2000). Surface disposal is generally limited to solid or semi-solid wastes such as drill cuttings, pipeline scale and pigging waste, tank and pit sludges, and contaminated soil. Surface disposal of one or more of these wastes at offsite facilities has been reported in at least 11 states (U.S. DOE, 2006). However, this is not assumed to be a comprehensive list because it is based on voluntary responses and does not include onsite disposal. The most common restrictions identified during the review of state programs involve the levels of chloride or TPH in the waste or the resulting soil-waste mixture. Some states also include restrictions on the activity of radioisotopes with limits set anywhere from 5 pCi/g above background to 30 pCi/g total activity, though a number of states have no documented limits. Further discussion of state-specific regulations is provided in Section 6 (State Programs). 7.2.1. Evaluation Summary Argonne National Laboratory used RESRAD (Version 5.782) to model the doses that may result from direct gamma exposure, inhalation of radon, and ingestion of local soil and produce. The evaluation considered multiple receptors that include residents, industrial workers and recreational users. The most significant differences between the modeled receptors is which exposure pathways are complete (e.g., ingestion of local produce) and the duration of exposure. The primary radionuclide of concern modeled in the evaluation was radium because these radioisotopes and the immediate progeny are those most likely to concentrate in these wastes and drive risk. Because exposures to radiation can be scaled based on the activity present, the evaluation used a unitized activity of 1 pCi/g 226Ra. The immediate, short-lived progeny (half-life less than a year) were assumed to be in secular equilibrium with the applied radium. To address uncertainty about the final soil activity, ANL modeled doses were adjusted to values ranging between 5 and 2,000 pCi/g 226Ra. As part of a sensitivity analysis, additional contributions from 228Ra were estimated as 30% of the activity of 226Ra. U.S. DOE (1998) found that a surface soil activity of 5 pCi/g 226Ra above background resulted in an additional 30 mrem/yr exposure from gamma radiation. Radon accumulation in the home increased the modeled doses to 60 mrem/yr. All other pathways contributed less than 5% to the total dose. Based on these results, the authors recommended that states that allow landspreading of E&P waste to activities greater than 5 pCi/g above background should consider establishing policies that will restrict future land use or, at a minimum, ensure that future land owners are advised of the activities and the potential associated health risks. 7.2.2. Uncertainties As with any evaluation, there are uncertainties. Some may arise from the practical limitations of models and data available at the time, while others are driven by changes to the industry practices in the decades since the evaluation was finalized. The following discussion summarizes key uncertainties Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-7 identified during this review and, where practicable, how consideration of more recent data might alter the evaluation findings. Total Radium The lowest identified state limits of 5 pCi/g reflect the combined contributions from 226Ra and 228Ra. U.S. DOE (1998) did not account for this limit on combined activities. Instead the authors assumed that the activity of 228Ra was a third of the longer-lived 226Ra isotope. Therefore, a 226Ra activity of 5 pCi/g would result in a total activity of approximately 6.7 pCi/g 226+228Ra. This has the potential to result in an overestimation of risk in areas where such limits are enforced. Erosion ANL assumed a uniform rate of erosion of approximately 0.04 in/yr that resulted in the eventual depletion of both topsoil and applied waste over time. This rate of soil erosion may occur around fields that are in active rotation where the soil is periodically disturbed, but may overestimate losses in areas adjacent to and particularly underneath a building. The presence of continuous vegetation and manmade structures that shield the soil will limit erosion from wind and encourage suspended soil particles to settle out of overland runoff. Thus, the assumed rate of erosion may underestimate long-term risks. Dose ANL compared modeled doses to the National Council on Radiation Protection and Measurements recommended annual dose limits for the general public of 100 mrem above background and concluded that exposures below 5 pCi/g were generally acceptable. The use of dose does not provide information about the magnitude of excess cancer risk. A dose rate of 100 mrem would result in risks considerably higher than the upper bound of the risk range used by RCRA of 1×10-6 to 1×10-4. Differences between dose and risk are attributable to how competing mortality risks and age-dependent radiation risk models are handled, the weighting of individual organs, as well as other dosimetric and toxicological assumptions (U.S. EPA, 1999c; 2014e; ISCORS, 2002). ANL did attempt to translate modeled doses to risk of fatal cancer based on conversion factors developed by the International Commission on Radiological Protection (ICRP, 1991). However, the risk of fatality will always be lower than the risk of cancer incidence that is the basis for the RCRA risk range. 7.2.3. Updated Analysis The review of the previous analysis indicates that some assumptions may overestimate or underestimate the magnitude of exposures on a case-by-case basis, though the largest uncertainty is the use of dose. Therefore, EPA updated the analysis with current models and data to estimate potential risks. EPA used RESRAD-OFFSITE version 3.2 (U.S. NRC, 2013) because the similar model framework allows a more direct comparison with the previous model results.21 The current version of RESRAD calculates risk with cancer slope factors based on the data from Biological Effects of Ionizing Radiation (BEIR) VII Phase 2: Health Risks from Exposure to Low Levels of Ionizing Radiation (NRC, 2006). This allows a direct comparison of results using the RCRA risk range. EPA selected model inputs based on data from 21) Use of this model does not represent an endorsement by EPA for use in other applications. EPA offices may evaluate similar exposure scenarios with other models based on the specific needs and requirements of each program. Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-8 the literature and Agency documents. For some inputs, particularly those related to waste properties and building design, insufficient data are available to construct full distributions. Instead, EPA selected high and low values to provide a bounding analysis. For inputs based on policy or that are considered less variable, EPA selected a single value to manage the number of model runs required. Table 7-4 presents a comparison of data used in the current analysis and U.S. DOE (1998). Table 7-4. Comparison of Inputs for RESRAD Model Parameters Current U.S. DOE (1998) Human Exposure Factors Fraction of Time Spent Indoors (%) Fraction of Time Spent Outdoors (%) 0.8 0.5 0.096 0.25 48 30 23 23 Exposure Duration (years) Inhalation Rate (m3/day) Waste Characteristics Radium Isotopes Ratio (228R/226Ra) 0.33 - 3.0 0.3 Radon emanation coefficient (unitless) 0.05 - 0.22 0.04 Application Depth (m) 0.02 - 0.2 0.2 Application Area (m2) 4,047 8,093 Building Characteristics Residential Air change per hour (1/hr) 0.18 - Room Height (m) Room Area (m2) Floor Thickness (m) 0.5 2.5 100 100 0.13 Effective radon diffusion coefficient of floor (m2/s) Density of floor and foundation 1.26 2.7 -8 2.1×10 (kg/m3) 0.15 -6 5.0×10 2,600 Total porosity of floor and foundation (unitless) Gamma Shielding Factor (unitless) - 2,000 0.16 0.2 - 3.0×10-7 0.10 0.7 0.7 The total range of values can sometimes span multiple orders of magnitude. This is because the current evaluation aims to provide both an upper and lower bound on highly exposed individuals. However, many of the selected values are similar to or encompass those used in the 1998 analysis. Further discussion of each variable and the data sources is provided below:  Inhalation Rates is the volume of air inhaled by an individual over a specified period of time. It determines the amount of radon taken into the lungs. The selected value is a weighted average of the 95th percentile inhalation rates for adults between the ages of 16 and 71 years old reported in Table 6-16 of the 2011 Exposure Factor Handbook (U.S. EPA, 2011).  Exposure Duration is the number of years that the receptor lives at a single residence. It determines the total amount of time a receptor is near the waste and potentially exposed. The selected value is the 90th percentile for resident farmers from Table 16-92 of the 2011 Exposures Factors Handbook (U.S. EPA, 2011). Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-9  Time Spent Indoors/Outdoors is the fraction of a day that a receptor spends indoors and outdoors while at home. It determines the fraction of time a receptor is exposed to external radiation with shielding from the walls of the house. It also determines the fraction of time a receptor is exposed to radon that accumulates within the home. The selected values are the reported averages for ages 18 to 64 reported in Table 16-22 of the 2011 Exposure Factor Handbook (U.S. EPA, 2011). The remaining time not accounted for between these two fractions is assumed to be spent away from home.  Radon Emanation Coefficient is the fraction of the generated radon that escapes from the waste matrix and is able to migrate into the surrounding air prior to decay. It determines the fraction of radon that is released and is available to enter a home. Emanation rates were drawn from available data for scale, sludge and contaminated media (API, 1990; Wilson and Scott, 1992; White and Rood, 2000). The lower end of values reflects intact pipe scale, while the higher end of values reflects disturbed scale and production sludge.  Radium Ratio is the relative amount of 228Ra and 226Ra isotopes in the applied waste. This is not a variable required by the RESRAD model. Instead, EPA used it along with the assumption to define initial radium activities. EPA reviewed available data from the literature (Appendix B: Constituent Database) to determine a range of radium ratios. Of those sources that reported activities for both isotopes, the ratios for scale ranged between 0.01 to 2.5 with an average of 0.7, while reported ratios for sludge ranged between 0.01 and 4.7 with an average of 0.5. Based on these data, EPA selected ratios of 1:3 and 3:1 to provide a reasonable range.  Application Area is the lateral extent over which the waste is spread. EPA selected 1-acre (4,047 m2), based on the assumption that the residence is centrally located. It is anticipated that waste application could cover an area considerably larger than a single acre. However, for the purpose of this model, this area is sufficiently large approximate an infinitely wide source. Increasing the area further will have negligible impacts on the calculated risk. For example, U.S. DOE (1998) found that decreasing the area from 4 to 0.2 acres decreased exposures by only five percent.  Application Depth is the depth below ground surface that the waste is incorporated into the soil. This mixing can dilute the activity of the waste and may contribute some additional shielding from overlying soil. EPA considered two values for the thickness of the contaminated zone. The first depth is 2 cm and represents surficial spreading without any active mixing. The second depth is 20 cm that represents soil tilled with a standard disk tiller. Both values are based on the recommended values in the Human Health Risk Assessment Protocol for Hazardous Waste Combustion Facilities (U.S. EPA, 2005).  Room Height is the vertical measurement of an average room in the residence. It determines the volume of air in the house in which radon can accumulate. The selected value was drawn from the U.S. Housing and Urban Development Residential Structural Design Guide (U.S. HUD, 2000). Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-10  Room Area is the floor area of an average room in the residence. It determines the volume of air in the house in which radon can accumulate. The selected value is the RESRAD default.  Air Exchange Rate is the number of times that the total volume of air in a housing unit is exchanged with outside air during a given time period. It determines the extent to which radon is able to accumulate in the home before it is cycled out. The selected values are the national 10th and 90th percentile values drawn from Table 19-24 of the 2011 Exposure Factors Handbook (US EPA, 2011).  Concrete Thickness is the distance that radon must migrate through the floor before it enters a home. It determines the rate at which radon can accumulate in a home. The selected values were drawn from the U.S. Housing and Urban Development Residential Structural Design Guide (U.S. HUD, 2000).  Concrete Density and Porosity are the compactness of the floor and the relative volume of void spaces through which radon can travel. These variables determine the rate at which radon can accumulate in a home. Values were drawn from Characterization of Radon Penetration of Different Structures of Concrete (U.S. DOE, 1996).  Shielding Factor is the fraction of the gamma ray energy that is absorbed by walls and other obstacles located between the waste and receptor. The shielding factor is applied only when the receptor is indoors. The lower value was drawn from Generic Procedures for Assessment and Response During a Radiological Emergency (IAEA, 2000). The higher value is the RESRAD default value. Denser materials, such as concrete and brick, offer higher shielding factors compared to other building materials, such as wood. EPA limited the scope of this analysis to a single scenario of a resident farmer living around the field where the wastes had previously been applied. EPA only modeled exposures to external radiation and radon because these were previously identified as the primary exposure pathways and there are greater uncertainties associated with other type of releases (e.g., leachate). EPA modeled risks up to 1,000 years following initial disposal of the waste with negligible losses to surface erosion or subsurface leaching. Available data indicate the fraction of radium leached from these wastes is often minimal. Anoxic conditions that may promote releases are not likely to form in the topsoil and any mass that is released may sorb onto surrounding soil. Therefore, the assumption of negligible losses is considered appropriate at this stage. The model was run deterministically with each combination of the inputs listed in Table 7-4. The model results are presented in Figure 7-1, plotted as a function of final soil activities ranging from 1 to 100 pCi/g. Given the radium activities measured in the various associated wastes, any of these soil activities could result from surface disposal in the absence of relevant restrictions. Each line on the graph reflects a different combination of inputs, with the top and bottom-most lines reflecting combination of all high-end and low-end inputs, respectively. Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-11 Gamma and Radon Gamma Only 1.E+00 1.E-01 1.E-01 1.E-02 1.E-02 1.E-03 1.E-03 1.E-04 1.E-04 1.E-05 1.E-05 Risk 1.E+00 1.E-06 1.E-06 1 10 Soil Activity (pCi/g) 100 1 10 100 Soil Activity (pCi/g) Figure 7-1: RESRAD Model Results With and Without Radon Exposure Potential risks from gamma radiation and radon greater than 1×10-5 are possible at every modeled soil activity. However, the model results do not provide any information about which of these results are most likely. It is possible that some of the modeled combinations are not realistic. For example, the lower radon emanation factor is associated with intact scale. However, removal from the well and mixing with the soil will inevitably disturb the integrity of scale, making higher emanation rates more likely. The range of potential risks from gamma radiation alone (right) is narrower than for combined gamma and radon (left). This is because many model inputs affect radon release and transport. Exposure to gamma radiation is a more direct pathway. The lower bound on modeled risks in both graphs are similar and attributed primarily to direct gamma exposure. 7.2.4. Findings U.S. DOE (1998) found that soil activities greater than 5 pCi/g can result in exposures greater than the dose limit of 100 mrem/yr recommended for the general public by the International Commission on Radiological Protection. The results of this update to that analysis confirm that exposure to these activities has the potential to result in doses that correspond to risks outside of the Office of Land and Emergency Management risk range. However, this update does not provide a likelihood that such risks will occur from current practices. Based on the activities measured in different E&P wastes (Section 5: Waste Characterization), uncontrolled land application of E&P wastes have the potential to result in soil activities at or above 5 pCi/g. However, it is not clear from available information which wastes are currently land applied. Past reports reference application of drill cuttings, drilling fluid, produced water and sludge. A number of states now have regulations in place that limit the activity in waste that can be applied. Even if a higher activity wastes are applied, it is not possible to estimate the resulting soil activity without more information on application rate and frequency. Therefore, there is not enough Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-12 information available from this existing evaluation to draw conclusions about the current disposal practices for E&P wastes. Conclusions The two identified evaluations indicate that adverse effects are possible from uncontrolled releases of E&P waste. Similar risks have been previously documented in historical damage cases. However, the majority of state regulatory programs now include specific requirements intended to prevent or substantially mitigate these types of risk. For example, the majority of states currently require some form of liner for pits that hold E&P waste and place limits on both where and how land application is allowed. Therefore, these types of uncontrolled releases are less likely to occur. To better understand the potential magnitude and frequency of environmental releases associated with current waste management practices, EPA reviewed the available literature for documented damage cases. Management of Oil and Gas Exploration, Development and Production Wastes Section 7: Existing Evaluations 7-13 8. Damage Cases As part of the 1987 Report to Congress (RTC), EPA gathered information on instances where ongoing management practices of E&P wastes had resulted in damage to human health and the environment. The Agency found evidence at the time that damages could occur in instances where these wastes were managed in accordance with applicable regulations. However, there have been considerable changes to both the oil and gas industry and state regulatory programs over the last thirty years. To better understand the effects of these changes, EPA conducted an updated review of recent damage cases that occurred in state, federal or tribal jurisdictions. The following section details the approach used to identify damages and the conclusions that can be drawn from the available information. Review of Recent Damage Cases EPA conducted a review of summary reports and other sources that had either been submitted to the Agency or identified through an independent literature search. Based on this review, EPA identified the following initial sources that had not previously been reviewed:  Oil Field Produced Water Discharges into Wetlands in Wyoming (U.S. DOI, 2002);  U.S. EPA Region 8 Oil and Gas Environmental Assessment Effort 1996-2002 (U.S. EPA, 2003);  2016 Notice of Intent to Sue for Violation of Nondiscretionary Duties under the Resource Conservation and Recovery Act with respect to Wastes Associated with the Exploration, Development, or Production of Oil and Gas.  Compendium of Scientific, Medical, and Media Findings Demonstrating Risks and Harms of Fracking (Unconventional Gas and Oil Extraction) (CHPNY and PSR, 2018); and  Individual news articles, scientific journals and state enforcement orders (Ramirez, 2010; Fehling, 2012; Vengosh et al., 2014; PADEP, 2014a,b; Flesher, 2015; ADSBRL, 2016; Fears, 2016; Lauer et al. 2016; Schladen, 2016; AP, 2018; Geeza et al., 2018; Pappas, 2018). The scope of damages considered in this review is broad and includes adverse health effects to humans and wildlife, impairment of habitat, and degradation of natural resources. However, it is important to note that this review only considered cases where a reasonably clear link of cause and effect exists between the waste management practice and the resulting damages. Because this review relied on welldocumented cases by necessity, it is not expected to be exhaustive. For example, damage claims that were settled outside of court are unlikely to be available in the public record. As a result, this review is not intended to provide a statistically representative sample of the type or frequency of damages that may occur. Instead, it aims to summarize the nature and extent of known damages and to highlight specific management practices that might warrant further review. Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-1 8.1.1. Review Criteria The Agency relied on a number of criteria to determine whether each of the reported incidents fell within the scope of the current review. Incidents that did not meet all the criteria were not retained for further consideration. EPA first applied the “tests of proof” used in the 1987 RTC to determine whether a reported incident qualifies as a damage case (U.S. EPA, 1987a,b,c). An incident was retained if there was sufficient information to classify it under one or more of the following categories:  Scientific Investigation: Damages were found to exist as part of the findings of a scientific study. Such studies could be extensive formal investigations supporting litigation or a state enforcement action, or they could, in some instances, be the results of technical tests (such as monitoring of wells) if such tests were a) conducted with state-approved quality control procedures and b) revealed contamination levels in excess of an applicable state or federal standard or guideline.  Administrative Ruling: Damages were found to exist through a formal administrative finding, such as the conclusions of a site report by a field investigator, or through existence of an enforcement action that cited specific health or environmental damages.  Court Decision: Damages were found to exist through the ruling of a court or through an out-ofcourt settlement. EPA further focused the scope of the current review to incidents that occurred between 2012 and 2018. During the most recent review of damage cases in 2010 (See: Section 2: Summary of Agency Actions), EPA concluded that a number of incidents had occurred years before the state in question had established relevant regulations and that enforcement of current regulations would prevent the vast majority of identified incidents from reoccurring. Therefore, EPA excluded older incidents both because of the timeframe of the previous review and the fact that older incidents are less likely to be representative of current waste management practices. This is consistent with the Agency’s review in the 1987 RTC that limited the review to the previous five years. The damage cases assembled in the 1987 RTC were broad and often included incidents that extend beyond the jurisdiction of RCRA. However, the scope of the current review is limited to whether revisions to RCRA Subtitle D regulations are necessary to address ongoing risks from the management of E&P wastes. Therefore, EPA focused the current review to include only management units that E&P wastes currently exempt from regulation under RCRA Subtitle C. For example, the current review did not address release incidents that result from disposal down injection wells. Nor did it address releases of salable petroleum products, unused chemical feedstock, and other non-wastes. EPA reviewed the release incidents reported in the identified sources based on the above criteria to ensure that the damage cases are both reliable and relevant to the current review. When an incident was judged not to be relevant, it was not retained for further review. When an incident was judged to be relevant or potentially relevant, EPA assembled as much specific information as possible about the location of the release, dates over which the release occurred, type and amount of waste released, the Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-2 contaminants of concern, type of management unit from which the waste was released, cause of the release, whether the release occurred during operations allowed under state regulations, regulatory response, and any criminal or civil penalties that resulted. However, many sources contain incomplete documentation of the incidents. When insufficient information was available to determine the nature of the release or the associated damages, EPA attempted to collect additional information from other available sources, such as references cited in the initial source document, state websites, and broader web searches. If the Agency was not able to find enough information to meet the test of proof, then these incidents were not retained for further review. 8.1.2. Findings Of the incidents reviewed, only eight met all the criteria and demonstrated a clear link between the management of E&P wastes and the resulting damages. Table 8-1 provides a summary of the available information for each of these incidents. A broader list of both the relevant and potentially relevant incidents considered in this review are provided in Appendix A (Damage Cases). Table 8-1. Summary of Relevant Damage Cases, 2012 – 2018 Location Release Dates Waste Type Reported COCs Unit Type Source Kern County, CA 1960 - 2018 Produced Water B, Cl Evaporation Pit, Spray Irrigation Seepage from Disposal Unit, Spray Irrigation Pittsburgh, PA 2011 - 2012 Produced Wastewater Cl Pit Liner Leakage Contaminated GW & SW, Impacted Vegetation Chartiers, PA 2012 Frac Fluid, Produced Water Cl, Mn Pit Liner Leakage Contaminated Soil Hopewell, PA 2013 Reuse Water Cl Pit Unspecified Leak Amwell, PA 2013 - 2014 Frac Fluid, Produced Water Cl Pit Pump Leak, Liner Leakage Contaminated Soil Mount Pleasant, PA 2014 Frac Fluid, Produced Water Not Reported Pit Unpermitted Discharge Soil Erosion, Deposition to Sediment in SW Body Yeager, PA 2014 Frac Fluids, Produced Water TDS, Cl Pit Unspecified Release Contaminated Soil & GW Midway, TX 2016 Frac Fluid, Produced Water Not Reported Wastewater Storage Tanks Flooding, Tank Failures Contaminated Soil & SW Reported Damages Contaminated GW Contaminated Soil & GW Eight incidents involved management of produced water (e.g., wastewater, flowback fluid, brine, reuse water) in pits and tanks. The magnitude of reported releases was highly variable, ranging in volume from approximately 1,300 gallons to over 500,000 gallons. Few sources provided information on the extent of contamination that resulted from these releases, but this may not have been known at the time damages were first identified. Available information shows that corrective action efforts have Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-3 begun or been ordered to begin at each of these sites. In one case, a fine of $4.5 million was also levied against the facility. Each of the eight incidents resulted in contamination of one or more environmental medium (i.e., soil, groundwater, surface water, sediment). Most damages were identified from measured concentrations, though few sources indicated what contaminant levels were present or what benchmarks were used for comparison. All of the reported contaminants are inorganic elements commonly found in produced water at elevated concentrations (Section 5: Waste Characterization). The most common contaminant was chloride. It is unclear if the contaminants reported served as an initial basis to identify damages or if the list reflects the full extent of contamination considered. There is potential for a number of other inorganic elements and organic compounds to be present in produced water and other E&P wastes, so partial characterization of the spill might result in incomplete remedial efforts. Four of the identified incidents were associated with units that were not in compliance with existing laws or regulations. For example, one incident (Pittsburgh, PA) involved the management of produced water in a pit that was only permitted to store fresh water. Another incident (Hopewell, PA) involved a pit that did not install the groundwater monitoring wells required by permit and so failed to identify subsurface leaks in a timely manner. A majority of the remaining incidents were a result of faulty or degraded equipment (e.g., poorly installed liners, tank collapse, leaks from pumps). It is noteworthy that a majority of the identified incidents occurred in Pennsylvania. However, it is highly unlikely that the actual frequency of releases is so disproportionately high in Pennsylvania compared to other states. Instead, given the high level of scrutiny that has been applied to the state in recent years due to increased concerns about drilling in the Marcellus shale, it is more likely to be a result of better documentation and communication with the public. Thus, the lack of damage cases identified in other states does not necessarily mean that none have occurred, nor does it mean that other states have not taken appropriate steps to address the environmental impacts from releases. However, the lack of available data for other states make it difficult to draw conclusions about the representativeness of the identified damage cases. Spill Reporting During the search of state websites associated with E&P waste regulatory programs, EPA identified four states that maintain centralized databases of spills that occur during site activities (i.e., Colorado, New Mexico, North Dakota, Wyoming). Although several other states collect information on spills, the data are extremely difficult to aggregate because specific information, such as the facility location (latitude and longitude) or the facility name is required to search the data (e.g., Oklahoma, Pennsylvania, Texas, West Virginia). The effort needed to assemble and review data for these additional states was prohibitive at this time. Regulations in these states require that spills above a set volumetric threshold be reported to the state within a certain timeframe. Identification and cleanup of the spills is conducted in accordance with state requirements for corrective action and so sites are typically not Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-4 subjected to fines in response. Because the releases are generally contained and addressed onsite without the need for enforcement action,22 these spills were not classified as damage cases. EPA reviewed the spill databases from the four states to identify data related to spills of E&P waste from waste management units (e.g., pits, tanks). Table 8-4 provides a summary of the available data over a 3-year period between 2014 and 2017. Table 8-2. Summary of Reported Spills for Select States, 2014 – 2017 State Colorado Unit Type Number of Active Units Number of Reported Releases Number Reported with Volume Total Reported Volume (BBLs) Average Reported Volume (BBLs) Pits 3,417 51 17 21,159 1,245 Tanks 1,441 529 206 14,150 69 Central Disposal 41 11 10 1,290 129 Pits NR 5 5 127 25 Not Reported (5) Tanks NR 516 433 82,262 190 Not Reported (197), Equipment Failure (169), Human Error (24) Total NR 408 407 203,566 500 Equipment Failure (349), Human Error (38) New Mexico Wyoming Most Frequent Spill Causes Not Reported (31), Equipment Failure (12), Human Error (8) Equipment Failure (251), Not Reported (235), Human Error (34) Human Error (6), Equipment Failure (4), Not Reported (1) NR – Not Reported Colorado: http://cogcc.state.co.us/cogis/IncidentSearch.asp New Mexico: https://wwwapps.emnrd.state.nm.us/ocd/ocdpermitting//Data/Incidents/Spills.aspx Wyoming: http://deq.wyoming.gov/admin/spills-and-emergency-response/ A similar number of total spills were identified across several states, though the typical volume released varied more widely. The most common waste reported by each state was produced water, which is also the largest volume waste generated during well production. Other wastes include drilling mud and tank bottoms. The reported spills can be generally categorized as resulting from equipment failure (e.g., damaged liner, breached berm, corrosion), weather events (e.g., flooding, lightning), and human error (e.g., overfilling). However, root causes do not always fall into neat categories, as equipment failure may sometimes be a form of human error due to poor maintenance or lack of planning. Nearly half of the incidents had no reported cause. The types of spills identified in this review align well with the findings of previous reviews of spills in other regions of the country (U.S. EPA, 2015b; 2016a). 22) For example, it has been reported that around 80% of spills in North Dakota are contained onsite (King and Soraghan, 2015). Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-5 Although the reported spills were identified between 2014 and 2017, that does not mean all of the spills originated during this timeframe. Some of the “historic” spills occurred at some earlier time, but were only identified during decommissioning of a tank battery, replacement of subgrade equipment, or other routine facility maintenance. Subsurface releases are more difficult to identify and this may explain the greater number of spills recorded for tanks. While groundwater monitoring may help to eventually detect leaks, contamination may not reach the installed wells before the unit is taken out of service for repair or decommissioned. Only one state, Colorado, provided information on how corrective action is implemented at spill sites. Colorado requires that the extent of soil and groundwater contamination be identified by sampling of soil and groundwater assisted with photoionization detector and the installation of temporary groundwater monitoring wells. Chemical analyses are generally limited to TPH, BTEX and select inorganics. Soil remediation typically involves excavation of the contaminated soil and/or in-situ treatment (e.g., stabilization). Groundwater remediation typically involves in-situ treatment (e.g., chemical oxidation, bioremediation), natural attenuation, and/or pumping groundwater to an offsite treatment facility. Sites are required to sample groundwater quarterly until relevant maximum contaminant levels are achieved. Of the 149 spills found to have reached groundwater between 2014 and 2017, 142 (95.3%) were considered resolved as of late-2017. State Inspection and Enforcement EPA searched the websites of thirty-five states for information on releases of E&P waste. During this search, EPA identified three states that published summary reports on the number of inspections and resulting enforcement actions taken on a yearly basis. These actions included both informal notices of the violation and formal enforcement orders. EPA did not include these violations in the list of damage cases because a number of violations identified did not involve actual releases to the environment. Rather, these other violations involved non-compliance with specific state requirements, such as failure to adequately label tanks or remove equipment from around inactive wells. Enforcement of these requirements helps prevent minor infractions from potentially becoming major releases. The violations that did result in releases are a clear result of non-compliance with state regulations, though there was not enough information available to define the type of waste involved, the cause of the release, or the resulting damages. Therefore, it is difficult to aggregate individual violations in a meaningful way. However, these reports still provide information that can be used to better understand the structure and implementation of state programs. Table 8-2 provides a summary of the available information for these three states. The number of inspectors was from state websites. EPA did not include supervisors or support staff (e.g., quality assurance officer) in the list of inspectors. Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-6 Table 8-3. Summary of State Inspections and Enforcement Actions in 2018 State Source Number of Inspectors Number of Inspections Number of Violations Penalties Assessed Colorado CODNR (2019) 20 Not Reported 163 $9,832,096 Pennsylvania PADEP (2018) 100* 35,556 2,290 $9,590,432 Texas TXRRC (2018) 158 130,064 29,964 $5,718,143 * Most recent data available from IPAA (2013). Colorado Inspectors: https://cogcc.state.co.us/about.html#/staffmaps Texas Inspectors: https://www.eenews.net/energywire/2017/02/09/stories/1060049755 State inspectors work to ensure compliance with applicable state regulations at both drilling sites and centralized waste disposal operations. Therefore, the number of inspectors and enforcement personnel employed by states is a useful metric that can be compared with different measures of enforcement (e.g., number of inspections) or production (e.g., number of wells) to better understand how the state programs are currently implemented. A greater number of inspectors relative to the number of facilities that require inspection is generally considered desirable because it would allow more regular inspection of individual sites. Infrequent inspections may allow violations to go unnoticed, particularly in remote or unpopulated areas, which may eventually result in environmental releases. Data for these states indicate that in 2016 each inspector visited an average of 356 wells in Pennsylvania and 781 wells in Texas. Data on the number of inspections was not identified for Colorado; however, the state reported that each inspector visited an average of 1,000 wells in 2015 (COOGTF, 2015). At these rates, it would take between 2.2 and 2.7 years to visit every well in these states, though it is unlikely each of the wells would be visited with the same frequency. States can and do place greater emphasis on inspections of certain operations. The Colorado Department of Natural Resources reports the use of a risk-based strategy to prioritize inspection of the phases of E&P operations considered most likely to experience violations (CODNR, 2014). A study conducted with data from the Pennsylvania Department of Environmental Protection found that the average time between inspections in this state increased from 0.3 years for newly installed wells to 2.8 years for those in operation for nearly a decade (Ingraffea et al., 2014). This compares well with the calculated average of 2.2 years for all wells. There is, however, no apparent correlation between the number of inspections conducted and the number of violations identified across the different states. States with fewer reported violations tended to levy higher individual fines. Larger fines may be used as a deterrent to compensate for fewer staff or less frequent inspections. However, it is not clear how states keep track of violations. The total number reported might capture each individual violation identified or only the sites where violations occurred. Therefore, it is difficult to draw meaningful comparisons among the states. As part of the 1987 RTC, EPA compared the number of inspectors and enforcement personnel in 12 states with the number of active oil and gas wells in the states. EPA updated this comparison for 11 of the same states based on the most recent data available. Data were not identified for Kansas and so it is not included in the current comparison. Table 8-3 provides estimates of the number of inspectors Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-7 employed relative to the number of active wells in each state. Recent estimates align well with the estimates for western states made in 2015 (COOGTF, 2015). Table 8-4. Summary of Inspection and Enforcement Personnel in Selected States, 1987 - 2018 1984-1986 2017-2018 Wells per Inspector Change to Wells per Inspector 5 484 ↑ 498% 3 3,854 ↑ 190% 50,874 40* 1,271 ↓ 30% 592 35,839 31 1,156 ↑ 95% 4,029 57,868 18 3,215 ↓ 20% 917 42,059 36 1,168 ↑ 27% 52 2,359 81,822 50 1,636 ↓ 31% 34 1,317 78,842 100* 788 ↓ 40% 120 2,323 305,895 158 1,936 ↓ 17% Active Wells Number of Inspectors Active Wells Number of Inspectors Alaska 1,295 16 Arkansas 11,982 9 81 2,421 1,331 11,563 California 56,645 31 1,827 Louisiana 40,259 New Mexico 40,294 68 10 Ohio 60,553 66 Oklahoma 122,667 Pennsylvania 44,789 Texas 278,811 State Wells per Inspector West Virginia 48,395 15 3,226 55,912 18 3,106 ↓ 4% Wyoming 14,438 12 1,255 33,366 11 3,033 ↑ 142% * Most recent data available from IPAA (2013). Alaska Inspectors: http://doa.alaska.gov/ogc/reports/reportsAndStudies/AOGCC_Statement_to_Gov.pdf Arkansas Inspectors: http://www.aogc.state.ar.us/about/staff.aspx Louisiana Inspectors: http://www.dnr.louisiana.gov/index.cfm/page/558#Engineering-Regulatory-Division-Direct New Mexico Inspectors: http://www.emnrd.state.nm.us/OCD/about.html Ohio Inspectors: http://oilandgas.ohiodnr.gov/inspectors Oklahoma Inspectors: http://www.occeweb.com/contactlist/ogcontacts.htm West Virginia Inspectors: https://apps.dep.wv.gov/oog/contact_new.cfm Wyoming Inspectors: http://wogcc.wyo.gov/home/contacts EPA noted in the 1987 RTC that enforcement of regulations was made more difficult in some regions of the country by the limited availability of state inspection and enforcement personnel. However, multiple states have decreased the number of inspectors over the past three decades. States that increased the number of inspectors are often those that have seen recent increases in production from tight oil and shale gas reservoirs. The magnitude of change in the well-inspector ratio ranges between a 40% decrease to a nearly 500% increase. Although the percent change is useful to track trends within a state, it does not provide a meaningful comparison between states as the state with the greatest increase (i.e., Alaska) still maintains the lowest overall ratio. In addition, statistics based on number of active wells may not adequately reflect the waste management units and other equipment associated with the wells that must also be inspected. There can be multiple pits and tanks present at a single drilling site. There can also be pits, tanks, and other management units (e.g., land application) at offsite disposal locations. Yet, as discussed in Section 4 (Waste Management), information available on the total number and location of such units in each state is limited. Based on inspection rates previously estimated for Colorado, Pennsylvania and Texas, it could take the remaining nine states anywhere from 0.3 to 10.8 years to cover all of the active wells with the current Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-8 number of inspectors. It is not apparent whether an ideal ratio of wells (or other metric) to inspectors exists. The same number of wells may need greater or fewer inspectors in different states based on a number of regional factors, such as the average distance between wells and the use of other methods to limit violations (e.g., spill reporting requirements, groundwater monitoring, higher fines). The frequency of inspections is an important consideration, but how inspectors interpret and enforce the state regulations are also important considerations. Therefore, it is critical that the inspectors are adequately trained to ensure both an understanding of the issues that may be encountered around E&P sites and consistent identification of and response to violations. This may accomplished through development of training standards, inspector certification programs or other technical assistance efforts. Some states have standardized training programs in place and some have taken public steps in recent years to invest additional resources. West Virginia developed a standardized observation checklist and an operations and maintenance questionnaire for the inspection of pits and tanks to ensure the field observations were recorded in a consistent method in response to a study in 2013 commissioned by the state legislature (WVDEP, 2013). In 2016, California awarded a contract to TOPCORP, an educational consortium composed of the Colorado School of Mines, Pennsylvania State University and University of Texas at Austin, to train inspectors through a combination of online training, classroom instruction and field experience. Conclusions EPA reviewed the release incidents that had been submitted to the Agency, as well as additional incidents identified during this review, to understand the type and frequency of releases from waste management units containing E&P wastes. Altogether, this review identified eight confirmed damage cases. During the damage case review, EPA also identified several state databases that provide information on the number of violations identified during inspections or reported spills. The databases include thousands of additional incidents; however, these incidents were not counted as damage cases because there was no evidence provided of adverse effects. Reported violations did not always involve releases to the environment. A number involved non-compliance with specific state requirements, such as failure to adequately label tanks or remove equipment from around inactive wells. Reported spills did involve releases to the environment; however, these releases were often limited by secondary containment and were addressed upon discovery without the need for state enforcement action. The conclusions that can be drawn from available data on violations and spills are more limited because these datasets primarily represent instances where the existing regulations were successfully enforced. However, the types of releases observed from spills align well with findings identified in both in this current review for damage cases and a previous reviews of spills conducted by the Agency (U.S. EPA, 2015b; 2016a). EPA studied the available data to determine whether patterns exist in the type and frequency of releases. It does not appear that any one type of waste management unit is more likely to result in releases; however, little information was identified for some types of waste management units Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-9 (e.g., land application). The available data indicated that a greater proportion of the identified damage cases involved pits and a greater proportion of reported spills involved tanks. It is possible that releases to the subsurface from pits and buried equipment make it more difficult to identify releases from equipment failure. However, routine maintenance and inspections during the operational life of the unit, as well as requirements to survey the area when a unit is taken out of service for periodic cleaning or repair can help to ensure that releases are identified and remediated. EPA found no indication that the types of uncontrolled releases from waste management units identified in historical damage cases are common. The two main causes of releases identified from E&P operations are now equipment failure (e.g., corrosion) and human error (e.g., overfilling tanks). These types of releases can be mitigated within the framework of existing state programs through increased enforcement of existing state regulations. However, some states appear to have reduced the number of inspectors relative to the number of active wells over the past three decades. This indicates that there is an opportunity to improve compliance through greater resources toward enforcement. Management of Exploration, Development and Production Wastes Section 8: Damage Cases 8-10 9. Summary and Conclusions In 1988, EPA issued a regulatory determination that exempted wastes associated with the exploration, development and production (E&P) of crude oil, natural gas and geothermal energy from Subtitle C of RCRA (53 FR 25446). Over the last three decades, there have been significant advancements in the production of crude oil and natural gas from hydraulic fracturing and directional drilling used to access black shale, tight oil and other “unconventional” formations. This document reviews the information currently available to the Agency about the generation, management and ultimate disposal of E&P wastes, assesses the likelihood of adverse effects to human health or the environment from current practices and presents EPA’s determination of whether revisions to federal regulations are necessary to address the identified risks. This review focused primarily on E&P wastes from crude oil and natural gas, as available data indicate that geothermal production remains limited to a few states and has not undergone a similar surge in production. This section summarizes the findings of EPA’s review and documents the Agency’s rationale for why revisions to regulations for E&P waste management are not necessary at this time, based on the currently available information. In the 1988 Regulatory Determination, EPA laid out a multi-pronged strategy to identify and address issues posed by the management of E&P wastes, that included working to improve state programs as well as addressing gaps in federal Subtitle D regulations. The Agency has since taken a number of steps to improve existing waste management programs by supporting independent reviews of state programs (e.g., State Review of Oil and Natural Gas Environmental Regulations) and compiling existing guidance and information on best management practices (e.g., U.S. EPA, 2014b). These efforts have resulted in substantive changes to state regulations for pits, tanks, offsite disposal, centralized facilities, spill reporting, corrective action, remedial standards, and other areas. EPA has also undertaken a number of important efforts and actions related to E&P operations under other Agency programs, such as a study of the potential impacts of hydraulic fracturing on drinking water resources (U.S. EPA, 2016a) and new regulations that address effluent limitation guidelines and pretreatment standards for oil and gas operations (44 FR 22069, 58 FR 12454, 61 FR 66086, 66 FR 6849, 81 FR 41845). In 2016, EPA was sued for its alleged failure to review and, as necessary, revise its federal nonhazardous solid waste regulations for E&P wastes. This lawsuit was based on section 2002(b) of RCRA, which requires every regulation promulgated under the Act to be reviewed and, where necessary, revised not less frequently than every three years. In response to the lawsuit, EPA entered into a consent decree to conduct the review and formally document whether revisions are necessary at this time. To support this effort, EPA conducted an extensive literature review of government, industry and academic sources to supplement the information available from previous Agency actions. EPA also conducted a review of available information on factors such as management practices, waste Management of Exploration, Development and Production Wastes Section 9: Summary and Conclusions 9-1 characteristics, state programs and damage cases in order to determine whether changes to the federal solid waste regulations are necessary. In sum, the combined use of hydraulic fracturing and directional drilling has altered the energy production landscape in the United States. Production in some states, such as North Dakota and Pennsylvania, has increased by nearly an order of magnitude in the past decade. As of 2017, horizontal wells accounted for nearly 13% of active wells in the United States (U.S. DOE, 2018e). Although the number of newly installed wells has declined sharply in recent years, production has continued to increase as a result of higher production rates from the horizontal wells (IPAA, 2017; U.S. DOE, 2018c,d). Increased production has the potential to generate greater volumes of waste. Some states collect and maintain data on the volumes of E&P wastes generated within their respective borders, but the methods and metrics used to collect these data are not uniform and so waste volumes reported at a national scale are only estimates. It is clear from available data that produced water accounts for the vast majority of the wastes generated, followed distantly by wastewater treatment residuals, spent drilling fluid and drill cuttings (API, 2000). A number of other waste liquids and solids are generated at far lower volumes and may be comingled in the same pits and tanks as higher-volume wastes prior to disposal. Available data indicate that a considerable fraction of both liquids and saturated solids are disposed through injection into deep formations; however, this disposal method falls outside the scope of the RCRA Subtitle D regulations in 40 CFR Part 257. There are a number of other options available for both onsite or offsite management of the remaining wastes, depending on the local infrastructure and state regulatory requirements. States with higher oil and gas production are more likely to have centralized or commercial facilities designated specifically for the treatment and disposal of E&P wastes. States with lower production are more likely to utilize existing infrastructure for nonhazardous wastes. However, the way that wastes are ultimately managed is primarily a decision made by industry within the bounds of applicable state and federal regulations. Both hydraulic fracturing and directional drilling have the potential to impact the composition of E&P wastes. EPA reviewed publicly available data on the composition and behavior of these wastes. This review shows that there can be orders-of-magnitude variability in the composition of each waste type, though trends are apparent for certain constituents that might be used to predict where elevated levels are more likely to occur. Some inorganic elements (e.g., lithium, molybdenum), organic compounds (e.g., benzene) and radioisotopes (e.g., radium) appear to be correlated with either the organic carbon content of the source rock or the salinity of the formation water. Horizontal wells are frequently drilled a greater distance through organic-rich rocks with saline formation water, and therefore higher constituent levels may be more common in the wastes from these wells, but similar orders-ofmagnitude levels can be possible in the wastes from vertical wells. Therefore, it is likely that similar regulatory controls would be appropriate for the wastes from both types of wells. However, waste composition is not static. Wastes may be intermingled during storage or treated in preparation for Management of Exploration, Development and Production Wastes Section 9: Summary and Conclusions 9-2 disposal, which may result in dilution or concentration of constituent levels. Therefore, it is important to understand the waste composition and behavior at the time of disposal to determine whether the wastes are being managed appropriately. EPA reviewed state regulations for E&P wastes to determine the scope of coverage (e.g., the wastes and activities), and the level of detail and precision in the requirements. This analysis provided an understanding of state programs and whether each program includes elements that are part of comprehensive waste management programs (e.g., waste containment, monitoring, unit closure), and that would likely be elements of a revised federal solid waste regulation were that deemed to be necessary. EPA reviewed 28 of the 34 states with reported oil and gas production, which together account for over 99% of oil and gas production in the United States. The result of this review shows that states are actively engaged in addressing the challenges posed by increased E&P operations, and have been responding in part by updating their waste management programs. A total of 24 states, which account for approximately 95% of national production, have updated their regulations applicable to E&P wastes since 2013. The scope and specificity of regulatory programs varies among the states, based on multiple factors such as the quantity of oil and gas produced in the state and the prevalence of hydraulically fractured wells. Despite this variability, EPA found that states incorporate many of the regulatory elements that are important components of waste management programs, such as requiring liners for pits, secondary containment and groundwater monitoring. This provides confidence that the scope of current state programs is robust. However, the way that regulations are interpreted and implemented is also important considerations. To better understand which practices may pose concern, EPA also reviewed the assembled literature for existing evaluations that had drawn conclusions about the potential for adverse effects from management of E&P wastes. Two existing evaluations identified potential adverse effects associated with uncontrolled releases from pits and land application. EPA reviewed both to determine whether the data and analyses that underpin these findings are of sufficient quality to support conclusions about the current management of E&P wastes. Based on this review, EPA concluded that the identified risks are possible when no controls are in place, as has been previously documented in historical damage cases. However, many state programs now include specific requirements that address issues, such as liners for pits, limits on land application, and other standards that address the risks associated with historical damage cases. Therefore, EPA also reviewed available data on recent environmental releases to better understand the current performance of state programs. EPA reviewed the release incidents that had been submitted to the Agency, as well as additional incidents identified during this review, to understand the type and frequency of releases from E&P waste management units. EPA considered releases from these units that resulted in documented adverse health impacts to humans and wildlife, impairment of habitat or degradation of natural resources. EPA further focused this review to releases that had occurred or were ongoing in the past six years to best reflect current management practices. Applying these criteria, this review identified eight damage cases. During the review of damage cases, EPA also identified several state databases that Management of Exploration, Development and Production Wastes Section 9: Summary and Conclusions 9-3 provided information on the number of violations identified during inspections and reported spills. The databases include thousands of additional incidents; however, these releases were not counted as damage cases because there was no evidence available of adverse effects. Reported violations did not always involve releases to the environment. A number involved non-compliance with specific state requirements, such as failure to adequately label tanks or to remove equipment from around inactive wells. Reported spills did involve releases to the environment; however, these releases were often limited by secondary containment and were addressed upon discovery without the need for state enforcement action. EPA reviewed the available data to determine whether patterns exist in the type and frequency of releases and found no indication that the types of uncontrolled releases identified in historical damage cases are common. Instead, human error (e.g., overfilling tanks) and equipment failure (e.g., liners damaged during solids removal) are the two main causes identified from the available data. These types of releases can be appropriately and more readily addressed within the framework of existing state programs through increased inspections, improved enforcement and other targeted actions than through the imposition of addition requirements under subtitle D of RCRA. Based on the information gathered for this review, EPA concludes that revisions to the federal regulations for the management of E&P wastes under Subtitle D of RCRA (40 CFR Part 257) are not necessary at this time. The oil and gas industry has undergone a significant transformation in recent years from the use of directional drilling and hydraulic fracturing to access unconventional formations, but states have also revised their regulatory programs to adapt to the challenges posed by these technological advancements; some within the last year. While higher constituent levels may occur more frequently in wastes from newer horizontal wells, similarly high levels are also possible in wastes from vertical wells. Therefore, it is likely that similar regulatory controls are appropriate for the wastes from both types of wells. Based on EPA’s review, current state programs incorporate the majority of elements that are important components of waste management programs, which indicates that the scope of existing regulatory programs is robust. There is considerable diversity in how these elements are incorporated in the different state programs, and so how the programs are implemented is also an important consideration. EPA therefore also examined the implementation of state programs based on the frequency, magnitude and extent of recorded releases. Historical damage cases and evaluations have shown that adverse effects can result from uncontrolled releases of E&P wastes. However, there is currently no evidence that these types of releases are common, as majority of the recently identified releases were well-contained and addressed onsite. The primary causes identified for these releases were human error and non-compliance with existing state regulations. The available information does not indicate that new federal solid waste regulations would prevent or substantially mitigate these types of releases. Instead, human error and non-compliance can be appropriately and more readily addressed within the framework of existing state programs through increased inspections, improved enforcement and other targeted actions. EPA will continue to work with states and other organizations to identify Management of Exploration, Development and Production Wastes Section 9: Summary and Conclusions 9-4 areas for continued improvement and to address emerging issues to ensure that E&P wastes continue to be managed in a manner that is protective of human health and the environment.23 23) EPA signed a memorandum of understanding with STRONGER on November 19, 2018 to collaborate and improve both environmental protections and economic outcomes through enhanced enforcement and compliance efforts for E&P waste management. Management of Exploration, Development and Production Wastes Section 9: Summary and Conclusions 9-5 10. References Abualfraj, N., P.L. Gurian and M.S. 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U.S. EPA. 1992a. “Background for NEPA Reviewers: Crude Oil and Natural Gas Exploration, Development, and Production.” Prepared by the Science Applications International Corporation for the EPA Office of Solid Waste under Contract Number 68-W0-0025. Washington, DC. June. U.S. EPA. 1992b. “Management of Wastes from Crude Oil and Natural Gas Exploration, Development, and Production on Alaska's North Slope.” Prepared by the EPA Office of Solid Waste and Emergency Response. Washington, DC. May. U.S. EPA. 1993. “Diffuse NORM Wastes - Waste Characterization and Preliminary Risk Assessment.” RAE-9232/1-2. Prepared by J. Dehmel of SC&A, Inc. and V.C. Rogers of Rogers & Associates Engineering Corp. under Contract No. 68-D20-155 for the Office of Radiation and Indoor Air. Washington, DC. May. U.S. EPA. 1994. “An SAB Report: Review of Diffuse NORM Draft Scoping Document.” EPA-SAB-RAC94-013. Prepared by the Science Advisory Board. Washington, DC. May. U.S. EPA. 1996. “Development Document for Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category.” EPA-821-R-96-023. Prepared by the Office of Water. Washington, DC. October. U.S. EPA. 1999a. “MINTEQA2/PRODEFA2, A Geochemical Assessment Model for Environmental Systems: User Manual Supplement for Version 4.0.” Prepared by HydroGeoLogic, Inc. and Allison Geoscience Consultants, Inc. for the Office of Research and Development. Athens, GA. September. U.S. EPA. 1999b. “The Vadose and Saturated Zone Modules Extracted from EPACMTP for HWIR990.” Prepared by HydroGeoLogic, Inc. for the Office of Solid Waste. Washington, D.C. August. U.S. EPA. 1999c. “OSWER Radiation Risk Assessment Q&A’s Final Guidance.” OSWER Directive 9200.4-31P. Prepared by the Office of Solid Waste and Emergency Response. December. U.S. EPA. 2000a. “Associated Waste Report: Crude Oil Tank Bottoms and Oily Debris.” Prepared by the EPA Office of Solid Waste. Washington, D.C. January. U.S. EPA. 2000b. “Associated Waste Report: Completion and Workover Wastes.” Prepared by the EPA Office of Solid Waste. Washington, D.C. January. Management of Exploration, Development and Production Wastes Section 10: References 10-15 U.S. EPA. 2000c. “Associated Waste Report: Dehydration and Sweetening Wastes.” Prepared by the EPA Office of Solid Waste. Washington, D.C. January. U.S. EPA. 2000d. “Development Document for Final Effluent Limitations Guidelines and Standards for Synthetic-Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category.” EPA-821-B-00-013. Prepared by the Office of Water. Washington, DC. December. U.S. EPA. 2002. “Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations.” EPA530-K-01-004. Prepared by the EPA Office of Solid Waste. Washington, D.C. October. U.S. EPA. 2003. “Oil and Gas Environmental Assessment Effort 1996 - 2002.” Prepared by EPA Region 8. Denver, CO. January. U.S. EPA. 2005. “Human Health Risk Assessment Protocol for Hazardous Waste Combustion Facilities.” EPA/530/R-05/006. Prepared by the EPA Office of Solid Waste and Emergency Response. Washington, DC. U.S. EPA. 2011. “Exposure Factors Handbook: 2011 Edition.” EPA/600/R-090/052F. Prepared by the Office of Research and Development. Washington, DC. September. U.S. EPA. 2013. “Beneficial Use of Waste Materials: State of the Practice 2012.” EPA/600/R-13/260. Prepared by RTI International and Innovative Waste Consulting Services, LLC under contract EPW-09-004 by for EPA Office of Research and Development. Cincinnati, OH. September. U.S. EPA. 2014a. “Memorandum: Review of State Oil and Natural Gas Exploration, Development, and Production (E&P) Solid Waste Management Regulations.” Prepared by the EPA Office of Solid Waste and Emergency Response. Washington, DC. April. U.S. EPA. 2014b. “Compilation of Publicly Available Sources of Voluntary Management Practices for Oil and Gas Exploration & Production (E&P) Wastes as They Address Pits, Tanks, and Land Application.” Prepared by the EPA Office of Solid Waste and Emergency Response. Washington, DC. April. U.S. EPA. 2014c. “Leaching Test Relationships, Laboratory-to-Field Comparisons and Recommendations for Leaching Evaluation using the Leaching Environmental Assessment Framework.” EPA 600/R-14/061. Prepared by D.S. Kosson and A.C. Garrabrants of Vanderbilt University, H.A. van der Sloot of Hans van der Sloot Consultancy, and P.F.A.B Seignette of the Energy Research Centre of the Netherlands for the Office of Research and Development under Contract No. EP‐C‐09‐027. Research Triangle Park, NC. October. Management of Exploration, Development and Production Wastes Section 10: References 10-16 U.S. EPA. 2014d. “Human and Ecological Risk Assessment of Coal Combustion Residuals.” Regulation Identifier Number: 2050-AE81. Prepared by the Office of Solid Waste and Emergency Response. Washington, D.C. December. U.S. EPA. 2014e. “Radiation Risk Assessment at CERCLA Sites: Q&A.” OSWER Directive 9285.6-20. Prepared by the Office of Solid Waste and Emergency Response. June. U.S. EPA. 2015a. “Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0” EPA/601/R-14/003. Prepared by the EPA Office of Research and Development. Washington, DC. March. U.S. EPA. 2015b. “Review of State and Industry Spill Data: Characterization of Hydraulic FracturingRelated Spills” EPA/601/R-14/001. Prepared by the EPA Office of Research and Development. Washington, DC. May. U.S. EPA. 2016a. “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” EPA-600-R-16-236Fa. Prepared by the Office of Research and Development. Washington, DC. December. U.S. EPA. 2016b. “Technical Development Document for the Effluent Guidelines and Standards for the Oil and Gas Extraction Point Source Category.” EPA-820-R-16-003. Prepared by the Office of Water. Washington, DC. July. U.S. EPA. 2016c. “Beneficial Use Compendium: A Collection of Resources and Tools to Support Beneficial Use Evaluations.” EPA 530-R-16-009. Prepared by the EPA Office of Land and Emergency Management. June. U.S. GAO (United States Government Accountability Office). 2012. “Information on the Quantity, Quality, and Management of Water Produced during Oil and Gas Production.” GAO-12-156. Washington, DC. January. U.S. HUD (United States Department of Housing and Urban Development). 2000. “Residential Structural Design Guide: 2000 Edition. State-of-the-Art Review and Application of Engineering Information for Light-Frame Homes, Apartments, and Townhouses.” Prepared by NAHB Research Center, Inc. under Contract No. H-21065CA. Washington, DC. February. U.S. NRC (United States Nuclear Regulatory Commission). 2013. “New Source Term Model for the RESRAD-OFFSITE Code Version 3.” NUREG/CR-7127. Prepared by C. Yu, E.K. Gnanapragasam, J.J. Cheng, S. Kamboj, and S. Y. Chen of the Argonne National Laboratory. December. UWCE (University of Wisconsin Cooperative Extension). 2005. “Wisconsin Minimum Design and Construction Standards for Concrete Mixing and Loading Pads and Secondary Containment Structures.” February. Management of Exploration, Development and Production Wastes Section 10: References 10-17 WYDEQ (Wyoming Department of Environmental Quality). 1990. “Toxicity and Radium-226 in Produced Water - Wyoming’s Regulatory Approach.” In Proceedings of the First International Symposium on Oil and Gas Exploration and Production Waste Management Practices (pp. 987994). New Orleans, LA. White, G.J and A.S. Rood. 2000. “Radon Emanation from NORM-Contaminated Pipe Scale and Soil at Petroleum Industry Sites.” Journal of Environmental Radioactivity. 54:401-413. Wilde, P., T.W. Lyons and M.S. Quinby-Hunt. 2004. “Organic Carbon Proxies in Black Shales: Molybdenum.” Chemical Geology. 206:167-176. Wilson, A.J. and L.M. Scott. 1992. “Characterization of Radioactive Petroleum Piping Scale with an Evaluation of Subsequent Land Contamination.” Health Physics. 63(6):681-685. Wood, J. 2014. “Why Lightning is a Fire Risk for Fiberglass Saltwater Tanks.” The Christian Science Monitor. Published online by the Christian Science Monitor on 7/19/14. WVDEP (West Virginia Department of Environmental Protection). 2013. “Final Report Water Quality Literature Review and Field Monitoring of Active Shale Gas Wells Phase I For ‘Assessing Environmental Impacts of Horizontal Gas Well Drilling Operations.’” Prepared by P. Ziemkiewicz, J. Hause, B. Gutta, J. Fillhard, B. Mack, and M. O’Neal of West Virginia Water Research Institute for Division of Air Quality. Charleston, WV. February. WVDEP. 2015. “Examination of Leachate, Drill Cuttings and Related Environmental, Economic and Technical Aspects Associated with Solid Waste Facilities in West Virginia.” Prepared by the Marshall University Center for Environmental, Geotechnical and Applies Sciences. Charleston, WV. June. Zhang, T, R.W. Hammack, and R.D. Vidic. 2015. “Fate of Radium in Marcellus Shale Flowback Water Impoundments and Assessment of Associated Health Risks.” Environmental Science and Technology. 49:9347-9354. Zhang, T., K. Gregory, R.W. Hammack, and R.D. Vidic. 2014. “Co-precipitation of Radium with Barium and Strontium Sulfate and Its Impact on the Fate of Radium during Treatment of Produced Water from Unconventional Gas Extraction.” Environmental Science and Technology. 48:4596-4603. Zielinski, R.A., J.K. Otton, and J.R. Budahn. 2000. “Use of Radium Isotopes to Determine the Age and Origin of Radioactive Barite at Oil-Field Production Sites.” Environmental Pollution. 113:299-309. Zielinski, R.A. and J.R. Budhan. 2007. “Mode of Occurrence and Environmental Mobility of Oil-Field Radioactive Material at U.S. Geological Survey Research Site B, Osage-Skiatook Project, Northeastern Oklahoma.” Applied Geochemistry. 22:2125-2137. Ziemkiewicz, P.F. and Y.T. He. 2015. “Evolution of Water Chemistry During Marcellus Shale Gas Development: A Chase Study in West Virginia.” Chemosphere. 134:224-231. Management of Exploration, Development and Production Wastes Section 10: References 10-18 Vengosh, A., R.B. Jackson, N. Warner, T.H. Darrah and A. Kondash. 2014. “A Critical Review of the Risks to Water Resources from Unconventional Shale Gas Development and Hydraulic Fracturing in the United States.” Environmental Science and Technology. 48:8334-8348. Management of Exploration, Development and Production Wastes Section 10: References 10-19 Appendix A: Damage Cases This appendix provides a summary of the Agency’s review of damage cases discussed in Section 2 (Summary of Agency Actions) and Section 8 (Damage Cases) of the main text. EPA reviewed the release incidents that had been submitted to the Agency, as well as any additional incidents identified during this review, to understand the type and frequency of releases from the waste management units that contain E&P wastes. EPA considered releases from these units that resulted in documented adverse health impacts to humans and wildlife, impairment of habitat or degradation of natural resources. EPA further limited this review to releases that had occurred or were ongoing in the past six years to best reflect current management practices.  Attachment A-1: provides a list of sources on alleged release incidents of E&P waste provided by the Natural Resources Defense Council in the 2010 Petition for Rulemaking Pursuant to Section 6974(a) of the Resource Conservation and Recovery Act Concerning the Regulation of Wastes Associated with the Exploration, Development, or Production of Crude Oil or Natural Gas or Geothermal Energy.  Attachment A-2: provides the result of the Agency’s review of damage cases, which includes summaries of release incidents found to meet all of the review criteria, as well as those that appeared to meet the criteria but did not have sufficient information to determine the cause of the release, the adverse effects, or other pertinent information. Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-1 Attachment A-1: List of Sources Provided by NRDC for the 2010 Review of Damage Cases Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-2 1. Joseph F. Scavetta, RCRA 101: A Course in Compliance for Colleges and Universities, 72 Notre Dame Law Review (1997) 2. Natasha Ernst, Note, Flow Control Ordinances in a Post-Carbone World, 13 Penn State Environmental Law Review (2004) 3. James R. Cox, Revisiting RCRA’S Oilfield Waste Exemption as to Certain Hazardous Oilfield Exploration and Production Wastes, 14 Villanova Environmental Law Journal (2003) 4. EPA, Report to Congress, Management of Wastes from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy, Volumes 1–3 EPA530-SW-88003 (1987) 5. Regulatory Determination for Oil and Gas and Geothermal Exploration, Development and Production Wastes, 53 Fed. Reg. 25 (July 6, 1988) 6. EPA Region 8, An Assessment of the Environmental Implications of Oil and Gas Production: A Regional Case Study (Working Draft 2008) 7. 101 F.3d 772 (D.C. Cir. 1996) 8. Closing Argument of the New Mexico Citizens for Clean Air and Water, Dec. 2007, OCD Document Image No. 14015_648_CF[1] 9. Drilling Down: Protecting Western Communities from the Health and Environmental Effects of Oil and Gas Production (2007) 10. Railroad Commission of Texas, Waste Minimization in the Oil Field 11. Claudia Zagrean Nagy, California Department of Toxic Substances Control, Oil Exploration and Production Wastes Initiative (2002) 12. Kelly Corcoran, Katherine Joseph, Elizabeth Laposata, & Eric Scot, UC Hastings College of the Law’ Public Law Research Institute, Selected Topics in State and Local Regulation of Oil and Gas Exploration and Production 13. C. Tsouris, Oak Ridge National Laboratory, Emerging Applications of Gas Hydrates 14. Letter from West Virginia Department of Environmental Protection to William Goodwin, Superintendent Clarksburg Sanitary Board, July 23, 2009 15. Oklahoma Corporation Commission Oil and Gas Conversation Division, Guidelines for Responding to and Remediating New or Historic Brine Spills (2009) 16. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document Nos. 1631502, 1631508 17. A.H. Beyer, Chevron Oil Field Research Co., Technical Memorandum, Purification of Produced Water, Part 1—Removal of Volatile Dissolved Oil by Stripping (1972) Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-3 18. U.S. General Accounting Office, RCED-89-97, Safeguards Are Not Preventing Contamination from Injected Oil and Gas Wells (1989) 19. Keith Schneider, Radiation Danger Found in Oilfields Across the Nation, N.Y. Times, Dec. 3, 1990 20. N.Y. Department of Environmental Conservation, Draft Supplemental General Environmental Impact Statement (2009) 21. Abrahm Lustgarten & ProPublica, Natural Gas Drilling Produces Radioactive Wastewater, Scientific American, Nov. 9, 2009 22. Motion in Limine to Exclude Rogers and Associates Engineering Reports, Lester v. Exxon Mobil Corp., No. 630-402 (La. 24th Jud. Dist. Ct. 2009) 23. Wilma Subra, Louisiana Environmental Action Network, Comments on Hydraulic Fracturing to the Louisiana Senate Environmental Quality Committee, Mar. 11, 2010 24. Susan Riha et al, Comments on the Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program, Jan. 2010 25. U.S. Congress, Office of Technology Assessment, Managing Industrial Solid Wastes from Manufacturing, Mining, Oil and Gas Production, and Utility Coal Combustion—Background Paper (1992) 26. U.S. Fish & Wildlife Service, Region 6, Environmental Contaminants Program, Reserve Pit Management: Risks to Migratory Birds (2009) 27. Oil & Gas Accountability Project, Pit Pollution—Backgrounder on the Issues, with a New Mexico Case Study (2004) 28. U.S. Environmental Protection Agency, Technology Transfer Air Toxics: Acrylamide 29. T.A. Kassim, Waste Minimization and Molecular Nanotechnology: Toward Total Environmental Sustainability, in 3 Environmental Impact Assessment of Recycled Wastes on Surface and Ground Waters: Engineering Modeling and Sustainability (Tarek A. Kassim ed., 2005) 30. Texas Railroad Commission, Waste Minimization in Drilling Operations 31. Jonathan Wills, Muddied Waters, A Survey of Offshore Oilfield Drilling Wastes and Disposal Techniques to Reduce the Ecological Impact of Sea Dumping (2000) 32. American Petroleum Institute, Waste Management 33. Dara O’Rourke & Sarah Connolly, Just Oil? The Distribution of Environmental and Social Impacts of Oil Production and Consumption, 28 Annual Review of Environment and Resources (2003) Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-4 34. Testimony of Margaret A. Ash, OGCC Environmental Supervisor, In the Matter of Changes to the Rules and Regulations of the Oil and Gas Conservation Commission of the State of Colorado 35. The Endocrine Disruption Exchange, Potential Health Effects of Residues in 6 New Mexico Oil and Gas Drilling Reserve Pits Based on Compounds Detected in at Least One Sample, Nov. 15, 2007 36. Shannon D. Williams, David E. Ladd & James J. Farmer, U.S. Geological Survey, Fate and Transport of Petroleum Hydrocarbons in Soil and Ground Water at Big South Fork National River and Recreation Area, Tennessee and Kentucky, 2002–2003 (2006) 37. The Endocrine Disruption Exchange, Number of Chemicals Detected in Reserve Pits for 6 Wells in New Mexico That Appear on National Toxic Chemical Lists: Amended Document, Nov. 15, 2007 38. Letter from Roy Staiger, District Office Cleanup Coordinator, Texas Railroad Commission, to Exxon Mobil Corporation, Dec. 31, 2009 39. Oil & Gas Accountability Project, Spring/Summer 2006 Report (2006) 40. Wolf Eagle Environmental, Environmental Studies: Fugitive Air Emissions Testing, Impacted Soil Testing, Mr. and Mrs. Timothy Ruggiero (2010) 41. U.S.G.S., Toxic Substance Hydrology Program: BTEX 42. Eric Griffey, “Toxic drilling waste is getting spread all over Texas farmland,” Fort Worth Weekly (May 12, 2010) 43. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease Registry, ToxFAQs for Acetone (1995) 44. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease Registry, ToxFAQs for Arsenic (2007) 45. ScienceLab.com, Chemicals & Laboratory Equipment, Material Safety Data Sheet: Arsenic MSDS 1 (2008) 46. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease Registry, ToxFAQs for Barium (2007) 47. U.S. Department of Health & Human Services, Agency for Toxic Substances and Disease Registry, ToxFAQs for Radium (2007) 48. Chris Gray, Pits Cause Stink in Lafourche, Times-Picayune, July 14, 1997 49. Miguel San Sebastian, Ben Armstrong, & Carolyn Stephens, Outcomes of Pregnancy among Women Living in the Proximity of Oil Fields in the Amazon Basin of Ecuador, 8 International Journal of Occupational and Environmental Health (2002) Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-5 50. Anna-Karin Hurtig & Miguel San Sebastian, Geographical Differences in Cancer Incidence in the Amazon Basin of Ecuador in Relation to Residence near Oil Fields, 31 International Journal of Epidemiology (2002) 51. Henry Spitz, Kennith Lovins & Christopher Becker, Evaluation of Residual Soil Contamination From Commercial Oil Well Drilling Activities and Its Impact on the Naturally Occurring Background Radiation Environment, 6 Soil & Sediment Contamination: An International Journal (1997) 52. Joint Factual Statement, ¶¶ 10–27, U.S. v. Exxon Mobil Corp., (D.Col. 2009) 53. Bryan M. Clark, Dirty Drilling: The Threat of Oil and Gas Drilling in Lake Erie (2005) 54. Letter from Lisa Kirkpatrick, Chief, New Mexico Dept. of Game & Fish, Conservation Services Division, to Florene Davidson, Commission Secretary, EMNRD Oil Conservation Division (Jan. 20, 2006) 55. Letter from Lisa Kirkpatrick, Chief, New Mexico Dept. of Game & Fish, Conservation Services Division, to Florene Davidson, Commission Secretary, EMNRD Oil Conservation Division (Mar. 7, 2006) 56. Letter from Lisa Kirkpatrick, Chief, New Mexico Dept. of Game & Fish, Conservation Services Division, to Florene Davidson, Commission Secretary, EMNRD Oil Conservation Division (Feb. 2, 2007) 57. Press Release, Pennsylvania Department of Environmental Protection, Cattle from Tioga County Farm Quarantined after Coming in Contact with Natural Gas Drilling Wastewater (July 1 2010) 58. Amended Complaint at ¶ 32, Sweet Lake Land and Oil Co. v. Exxon Mobil Corp., No. 209CV01100, (W.D. La. filed Sept. 14, 2009), 2009 WL 4701364 59. Test results from Veterinary Medical Diagnostic Laboratory on 26 July 2005, 18 August 2005, and 6 September 2005 60. Bluedaze: Drilling Reform for Texas, http://txsharon.blogspot.com/2008/07/more-barnett-shalesludge-pond.html. (July 25, 2008) 61. Susan Hylton, Drilling Waste Feud, Neighbors of Maverick Energy Services Think Water is Being Polluted, Tulsa World, March 21, 2010 62. E&P Forum, Exploration and Production (E&P) Waste Management Guidelines (1993) 63. League of Women Voters of Tarrant County, Gas Drilling Waste-Water Disposal (2008) 64. Testimony of James E. McCartney to the 128th General Assembly, Ohio Senate Environmental and Natural Resources Committee. Opposition Testimony on Senate Bill 165, Oct. 28, 2009 65. State Review of Oil and Natural Gas Environmental Regulations, Inc., Tennessee State Review (2007) Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-6 66. FY2008 EPA Region 6 End-of-year Evaluation of the Railroad Commission of Texas Underground Injection Control Program, with transmittal letter from Bill Luthans, Acting Director, Water Quality Protection Division, Region 6 to Tommie Seitz, Director, Oil and Gas Division (June 19, 2009) 67. Joe Carroll, Exxon’s Oozing Texas Oil Pits Haunt Residents as XTO Deal Nears. Bloomberg. April 16, 2010 68. New Mexico Energy, Minerals and Natural Resources Department, Oil Conservation Division, Cases Where Pit Substances Contaminated New Mexico’s Ground Water (2008) 69. Oil & Gas Accountability Project, Groundwater Contamination 70. Kim Weber, Regarding Support of HB 1414—Evaporative Waste Facilities Regulations 71. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document Nos. 1630424, 1630426, 1630427, 1630428, 1630429, 1630430 72. Oil & Gas Accountability Project, Contamination Incidents Related to Oil and Gas Development, Maralex Drilling Fluids in Drinking Water 73. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Report, Document No. 1953000 74. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, NOAV Report, Document No. 200085988 75. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document Nos. 1631518, 1631599, 2605176, 2605847 76. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document Nos. 200225543, 200225547, 200225546 77. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document No.1632846 78. COGCC Prather Springs Administrative Order by Consent 79. Toxics Targeting, Inc., Hazardous Materials Spills Information Request (2009) 80. Consent Assessment of Civil Penalty, In re Atlas Resources LLC, Dancho-Brown 4, ¶¶ AV–AZ, Groves 8, ¶¶ BA–BE 81. Ohio Department of Natural Resources, Notice of Violation No. 1278508985, June 21, 2010. 82. Ohio Department of Natural Resources, Notice of Violation No. 2016754140, May 16, 2008. 83. Phillip Yates, Clean Air Group Contends Evaporation Ponds in Garfield County More Dangerous than Previously Believed, Post Independent, Jan. 9, 2008 Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-7 84. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Complaint Report, Document No. 200081602 85. Amended Complaint, Stephenson v. Chevron U.S.A, Inc., No. 209CV01454, (W.D. La. filed Sept. 11, 2009), 2009 WL 4701406 86. Petition for Damages, Brownell Land Corp., LLC v. Honey Well Int’l., No. 08CV04988, (E.D. La. filed Nov. 21, 2008), 2008 WL 5366168 87. Rice Agricult. Corp., Inc., v. HEC Petroleum Inc., 2006 WL 2032688 (E.D. La) 88. Petition for Damages, Tensas Poppadoc, Inc. v. Chevron U.S.A., Inc., No. 040769, (7th Judicial Court La. filed Sept. 21, 2005), 2005 WL 6289654 89. Petition for Damages to School Lands, Louisiana v. Shell Oil Co., No. CV04-2224 L-O, (W.D. La. filed Oct. 29, 2004), 2004 WL 2891505 90. State Review of Oil and Natural Gas Environmental Regulations, Inc., Kentucky State Review (2006) 91. State Review of Oil and Natural Gas Environmental Regulations, Inc., Louisiana State Review (2004) 92. Christie Campbell, Foul Odor from Impoundment Upsets Hopewell Woman, ObserverReporter, Apr. 14, 2010 93. EPA Office of Compliance Sector Notebook Project, Profile of the Oil and Gas Extraction Industry, EPA/310-R-99-006 (2000) 94. Letter from Gary M. Maslanka, New York State Division of Solid & Hazardous Materials, to Joseph Boyles, Casella (April 27, 2010) 95. Press Release, Arkansas Dept. of Envtl. Quality, ADEQ Releases Landfarm Study Report (Apr. 20, 2009) 96. M.G. Puder & J.A. Veil, Argonne National Laboratory, Offsite Commercial Disposal of Oil and Gas Exploration and Production Waste: Availability, Options, and Costs (2006) 97. Abrahm Lustgarten, State Oil and Gas Regulators Are Spread Too Thin to Do Their Jobs, ProPublica, December 30, 2009 98. EPA, Office of the Inspector General, Complete Assessment Needed to Ensure Rural Texas Community Has Safe Drinking Water, No. 2007-P-00034 (2007) 99. Robert D. Bullard, Testimony before the Subcommittee on Superfund and Environmental Health of the Senate Environment and Public Works Committee (July 25, 2007) 100. Marcellus Gas Well Hydrofracture Wastewater Disposal by Recycle Treatment Process, ProChemTech International, Inc. Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-8 101. New York State Water Resources Institute, Waste Management of Cuttings, Drilling Fluids, Hydrofrack Water and Produced Water 102. Ohio Environmental Protection Agency, Marcellus Shale Gas Well Production Wastewater 103. Joaquin Sapien, With Natural Gas Drilling Boom, Pennsylvania Faces an Onslaught of Wastewater, ProPublica, October 4, 2009 104. Marcellus Shale Natural Gas Wastewater Treatment, Hearing Before the S. Comm. on Environmental Resources and Energy (Pa. 2010) (statement of Peter Slack, Pennsylvania Municipal Authorities Association) 105. Press Release, Pennsylvania Department of Environmental Protection, DEP Says Jersey Shore Borough Exceeds Wastewater Permit Limits (June 23 2009) 106. Pennsylvania Department of Environmental Protection, Press Release, DEP Fines Atlas $85,000 for Violations at 13 Well Sites, Jan. 7, 2010 107. Laura Legere, Massive use of water in gas drilling presents myriad chances for pollution, Scranton Times-Tribune, June 22, 2010 108. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Report, Document No. 1630697 109. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document Nos. 1631155, 1631831, 1631794, 1632853 110. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document Nos. 1630885, 1631496, 1631519, 1632057, 2605191, 1632995 111. Colorado Oil and Gas Conservation Commission, Inspection/Incident Inquiry, Spill Reports, Document Nos. 200226284, 200225725, 2605709 112. Oil & Gas Accountability Project, Colorado Oil and Gas Industry Spills: A review of COGCC data (June 2002-June 2006) (2006) 113. Frac Fluid Spill Reported in Flower Mound, Cross Timbers Gazette, Mar. 17, 2010 114. Letter from Robert F. Fetty, Mayor, Town of West Union, to Barbara Taylor, Director, WVBPH/Office of Environmental Health Services, Oct. 28, 2009 115. Posting of Ken Ward Jr. to Sustained Outrage: A Gazette Watchdog Blog 116. Letter from Louanne McConnell Fatora to Governor Manchin, West Highlands Conservancy (Aug. 30, 2009) 117. U.S. Energy Information Administration, Number of Producing Gas Wells (2009) 118. Bureau of Land Management, BLM FY 2009 Budget Justifications III-1834 (2009) Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-9 119. Hannah Wiseman, Untested Waters: The Rise of Hydraulic Fracturing in Oil and Gas Production and the Need to Revisit Regulation, 20 Fordham Environmental. Law Review (2009) 120. Texas Railroad Commission, Newark, East (Barnett Shale) Field, Drilling Permits Issued 121. Newark, East (Barnett Shale) Drilling Permits Issued (1993-2009), Texas Railroad Commission 122. Industry Sets Record For Drilling, Well Completions, Land Letter, Jan. 18, 2007 123. API: US Drilling at 21-year High in 1Q, Oil & Gas Journal, May 7, 2007 124. Utah Department of Natural Resources, Division of Oil, Gas and Mining, Produced Water Disposal(2007) 125. EPA, Region 8, Oil and Gas Environmental Assessment Report 1996–2002 (2003) 126. Statement of Commissioner William Olson before the New Mexico Oil Conservation Division, Apr. 16, 2008, OCD Document Image 14015_657_CF[1] 127. “Governor Bill Richardson Announces Oil and Gas Drilling Activity in New Mexico Is Strong: Environmental regulations are not driving business away,” State of New Mexico, Press Release, May 19, 2010 128. Dorsey Rogers, Gary Fout & William A. Piper, New Innovative Process Allows Drilling Without Pits in New Mexico (2006) 129. Oil & Gas Accountability Project, Alternatives to Pits 130. Oil & Gas Accountability Project, Notice of Errata in the Oil & Gas Accountability Project’s Closing Argument and Proposed Changes, Re: Case 14015: Application of New Mexico Oil Conservation Division for Repeal of Existing Rule 50 Concerning Pits, etc., Dec. 11, 2007, OCD Document Image No.14015_654_CF[1] 131. Dorsey Rogers, Dee Smith, Gary Fout & Will Marchbanks, Closed-loop drilling system: A Viable Alternative to Reserve Waste Pits, World Oil, Dec. 2008 132. Exhibit 8, Closed-Loop Drilling Case Studies, Re: Case 14015: Application of New Mexico Oil Conservation Division for Repeal of Existing Rule 50 Concerning Pits, etc., OCD Document Image No. 14015_637_[CF]1 133. Abrahm Lustgarten, Underused Drilling Practices Could Avoid Pollution, ProPublica, Dec. 14, 2009 134. U.S. Fish & Wildlife Service, Wildlife Mortality Risk in Oil Field Waste Pits, U.S. FWS Contaminants Information Bulletin (2000) 135. Bureau of Land Management, The Gold Book: Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development (4th ed. 2007) Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-10 136. Controlled Recovery Inc.’s Written Closing Argument, Re: Case 14015: Application of New Mexico Oil Conservation Division for Repeal of Existing Rule 50 Concerning Pits, etc., Dec. 10, 2007 137. Lowell Brown, Officials Give Few Answers to Argyle, Denton Record-Chronicle, Jan. 30, 2010 138. E&P Forum/UNEP Technical Publication, Environmental Management in Oil and Gas Exploration and Production: An Overview of Issues and Management Approaches (1997) 139. STW Resources, Inc., Contaminated Waste Water Reclamation Opportunities 140. Railroad Commission of Texas, News Release, Commissioners Approve of Devon Water Recycling Project for the Barnett Shale, July 29, 2008 141. Energy Companies Strive to Reuse Water, Weatherford Telegram, July 25, 2007 142. Nine New Projects, Oil & Gas Program Newsletter (U.S. Dept. of Energy, National Energy Technology Lab), Winter 2009 143. Katie Burford, ExxonMobil Favors Fracing Disclosure, Environmental Group Welcomes Position from Oil Industry Giant, Durango Herald, Apr. 19, 2010 144. Drilling Waste Management Information System, Drilling Waste Management Fact Sheet: Using Muds and Additives with Lower Environmental Impacts 145. Schlumberger, Earth-friendly Green Slurry system for uniform marine performance, March 2003 146. Rifle, Silt, New Castle Community Development Plan, January 1, 2006 147. EPA, RCRA Orientation Manual, Chapter III: RCRA Subtitle C—Managing Hazardous Waste, Hazardous Waste Identification. 148. Hazardous Waste Treatment Council v. U.S. EPA, 861 F.2d 277, 279 (D.C. Cir. 1988) 149. U.S. Dept. of Labor, Occupational Safety & Health Administration, Potential Flammability Hazard Associated with Bulk Transportation of Oilfield Exploration and Production (E&P) Waste Liquids, SHIB-03-24-2008 150. Janice Crompton, Residents Reported Gas Odors Before Explosion, Pittsburgh Post-Gazette, Apr. 1, 2010 151. Kathie O. Warco, Fumes Ignite at Gas Well, Observer-Reporter, Apr. 1, 2010 152. Earthworks, OCD’s 2007 Pit Sampling Program: What is in That Pit? Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-11 Attachment A-2: Summary of Recent Damage Cases [Due to the file size, this spreadsheet is maintained as a separate file.] Management of Exploration, Development and Production Wastes Appendix A: Damage Cases A-12 Appendix B: Constituent Database This appendix provides a summary of the data collection efforts conducted in support of this document. The intent of the literature review is to assemble existing data that can form the basis for conclusions about the composition and behavior of wastes generated by exploration, development and production (E&P) operations. The data review process, as well as the rationale for exclusion of any data from the assembled sources, is discussed in the following sections. The citations in this appendix address only those sources cited in the body of this appendix. The E&P Database contains a full list of the citations associated with the dataset.  Attachment B-1: provides the E&P Database, which contains the constituent data relied upon in tis review to characterize concentrations present in and released from the different waste types. B.1. Data Collection EPA reviewed the available literature for studies that contained information on E&P waste. This initial review focused on publicly available data that that could be reasonably assembled without more formal information collection efforts. The purpose of this current effort was to determine whether the available data is sufficient to draw conclusions about E&P wastes and where additional data is needed to understand the impacts to human health and the environment that may result from the current management practices for these wastes. Some potentially relevant sources were already available from previous Agency investigations. EPA supplemented these sources with reports drawn from the webpages other federal and state agencies with jurisdiction over oil and gas well permitting, operation and/or waste management. EPA first reviewed these sources to develop a baseline understanding of the current universe of waste types, waste composition and drilling practices to focus further searches. EPA then queried multiple databases of peer-reviewed literature, such as Science Direct, with various combinations of descriptive keywords to capture the different wastes (e.g., produced water), constituents (e.g., radium) and drilling practices (e.g., hydraulic fracturing). Finally, EPA reviewed the citations from each study to identify any additional sources that had not yet been captured during the review. Once the citations list had been exhausted, EPA reviewed the identified studies, updated the baseline search terms, and repeated the literature search. This process was repeated until no new sources of information were identified. B.2. Data Quality Review EPA reviewed all the literature sources assembled to ensure that the data from each were of sufficient quality to form a basis for conclusions on the composition and behavior of E&P waste. The following subsections detail how the Agency applied the data quality assessment factors outlined in A Summary of General Assessment Factors for Evaluation the Quality of Scientific and Technical Information (U.S. EPA, 2003). The following subsections detail the review for each major assessment factor. When it was determined that data from a particular study was not relevant, it was excluded from the database. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-1 When individual data points or entire studies were found to introduce an unacceptable level of uncertainty, these data were filtered out from the dataset prior to any analyses. However, these data were left in the database for future reference. B.2.1 Evaluation and Review Evaluation and review is the extent to which the findings of a given study have undergone sufficient independent verification, validation and peer review. An independent review is one conducted by technical experts who were not associated with the generation of the work under review either directly through substantial contribution to its development, or indirectly through significant consultation during the development of the work. Independent review is intended to identify any errors or bias in how data are collected, handled or interpreted, and also to ensure that the findings are accurate and reliable. Data reported in grey literature has not necessarily undergone formal peer review, though some have been made publicly available for review and comment as part of past Agency rulemakings. Most of the data were collected in accordance with standardized analytical methods that have been validated. EPA relied primarily on raw data from these studies. Any further analyses of the data were only considered as supplementary lines of evidence to corroborate conclusions drawn from the data. External review of each study in isolation would not provide any indication whether the raw data are appropriate for the current application. Instead, EPA relied on other quality metrics to determine whether data was fit for purpose. EPA only excluded data from one study as a result of the level of evaluation and review. One study reported a large amount of leachate data for various wastes collected by a secondary source, but noted that only a subset of the data had been independently validated (LADNR, 1999). EPA retained all of the reported data in the E&P Database, but filtered our all non-validated samples prior to any analyses. B.2.2 Applicability and Utility Applicability and utility is the extent to which the data are relevant for the intended use. This means the purpose, design and findings of the study support the intended application of the data. EPA reviewed the assembled studies to ensure that the data contained in each are representative of generated E&P wastes and environmental conditions relevant to anticipated waste management scenarios. Waste Type: Data collection was focused on the wastes generated from E&P activities. Some studies reported data for samples outside of this scope. These data often reflected wastes generated at downstream refineries. These wastes may be similar in appearance to those generated at the drilling site, but the composition can be different as a result of losses during storage (e.g., volatilization) or treatment at the refinery to produce a salable product. This represents a major source of uncertainty and so these data were excluded from the E&P Database. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-2 EPA further focused the literature review on the waste types with the greatest amount of data available. These tended to be those either generated in the greatest volume (e.g., produced water) or those that pose specific management issues (e.g., well scale). There are a number of additional wastes generated during the course of E&P activities, such as rig wash (U.S. EPA, 2002). Little characterization data was identified for many of these additional wastes and so no conclusions could be drawn about the typical composition of these additional wastes. Many studies reported data on individual E&P waste types as generated (e.g., drill cuttings), but others reported data on E&P wastes after management with other E&P wastes (e.g., drilling solids) or treatment in anticipation of disposal (e.g., stabilization/solidification). All of these samples can provide useful information about the impact of management practices on waste composition and behavior. Therefore, EPA retained all the different sample types in the database, but flagged the relevant differences to facilitate comparison. Country of Origin: When reviewing the available literature, EPA drew data from any well drilled in North America. The country of origin was labeled for each sample in the E&P Database. It is unknown whether wastes from Canada or Mexico are substantially different from those in the United States given the sparseness of available data. However, if relationships exist between geology and waste composition as anticipated, then these data can still provide useful information. Therefore, EPA included data from Canada and Mexico in the E&P Database. These data were used to identify relationships between constituents, but were not incorporated in any summary statistics. Data from countries outside of North America were not incorporated in the database, but were considered as a secondary source of information to supplement discussion and corroborate findings. These international sources are cited in the main text where applicable. Well Type: EPA drew data for all well types during the review of the available literature, including wells used as a source of potable water and brine where the water produced is a valuable product instead of a waste. Some of these wells fall outside the scope of this document, but if relationships exist between geology and waste composition as anticipated, these data can still provide useful information. EPA incorporated the data for these other wells in the E&P Database with the well type flagged. Because these other well types are only used to supplement the waste data, EPA did not aim for a comprehensive review of the literature. Therefore, care should be taken when drawing any conclusions from the database about typical water composition from these wells. B.1.1 Soundness Soundness is the extent to which the methods employed by a literature source are reasonable and consistent with the intended application of the data. This means that any methods used to collect and measure data have demonstrated the technical ability to reliably and repeatedly achieve desired levels of accuracy and precision, and that any methods used to analyze and interpret data, such as equations; Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-3 models and simplifying assumptions, are adequately justified and rooted in accepted scientific principles. Analytical Methods: EPA reviewed the analytical methods used by each study to measure constituent levels in each waste. The purpose of this review was to determine whether the uncertainties associated with reported data could affect the conclusions in this document. The methods used by different studies varied based on the focus of the study and the equipment available to the authors. A few studies did not report the methods used or only noted that the samples had been sent to the U.S. Department of Interior Geological Survey or another certified laboratory for analysis. One consideration in this review was whether the methods used by a study accurately measured the constituent levels in an E&P waste. Methods that are not well-suited for high ionic strength wastes may result in imprecise data. For example, methods that dilute the waste prior to measurement can result in high detection limits for minor constituents (MSC, 2009), while those that precipitate constituent mass out of solution prior to measurement may underestimate constituent levels as a result of matrix interference (Nelson et al., 2014). The extent to which these uncertainties might affect the data is not known. Therefore, at this stage of investigation, EPA relied on other metrics, such as charge balance and agreement with observed relationships, to identify potential data quality concerns and avoid exclusion of useful data. If data from these studies were incorrectly measured, the error is likely to be reflected in the calculated charge balance. Therefore, EPA did not filter out any data solely because of the specific analytical method reported. Another consideration in this review was whether the study provides data appropriate for the intended use. Some analytical methods are designed to measure different aspects of waste composition. For example, non-destructive methods (e.g., neutron activation analysis) measure the total constituent mass within the sample matrix, while digestion methods (e.g., mass spectrometry) measure the constituent mass that can be liberated from the matrix with a combination of heat and acid. Both types of data can provide useful information on waste composition and behavior. Total concentrations measured by nondestructive methods better reflect the entire waste and can be used to demonstrate relationships among constituents in the total waste. The acid-extractable concentrations measured by digestion methods better reflect the fraction of the waste that is available to be released into the surrounding environment and can be used to estimate exposures. The resulting data are not necessarily equivalent and care should be taken before combining these data in a single dataset. Therefore, EPA compared data collected with different methods to determine if substantial differences exist. When such differences were identified, EPA separated the data out for further review and discussion in the text of this analysis. B.1.2 Clarity and Completeness Clarity and completeness is the degree to which a study transparently documents all assumptions, methods, results, and other key information. An evaluation that is both clear and complete provides enough detail that an outside party with access to the necessary resources can replicate the analyses. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-4 Units: Studies reported the data in variable units. Some expressed concentrations in terms of mass or molarity, while others reported concentrations per unit of volume or mass. All concentrations were converted into units of milligrams (mg) or picocuries (pCi) per liter (L) or kilogram (kg), based on the relevant media. Sometimes this conversion required the use of additional data or assumptions. For example, when density was not reported for an aqueous sample expressed per unit of mass, a density of 1.0 kg/L was used to convert to a volumetric concentration. This may result in an underestimation of concentration for some samples, as produced water density has been reported as high as 1.3 kg/L. However, the magnitude of this uncertainty is small in comparison to the orders-of-magnitude variability observed among the larger dataset. Any time that additional data or assumptions were required to calculate the concentration, the approach was flagged in the notes column of the database. In instances where data was insufficient to convert the reported units to mg/L with any certainty (e.g., reported in units of chemical activity), the samples were excluded from the database entirely. EPA identified two separate studies with indeterminate units for some samples. Both of these studies reported data for produced water. The first study, USEPA (2016a), reported data obtained from the Wyoming Oil and Gas Conservation Commission. Despite outreach to the Commission, EPA could not confirm units for many minor constituents. As such, EPA filtered out the constituents with uncertain units prior to the any analyses. The second study, U.S. DOI (2016), is a database compiled from sources assembled by the United States Geological Survey and other organizations.B1 In this second study, all of the data is reported to be in units of milligrams or picocuries per liter. Yet during the literature review, EPA identified one source document (U.S. DOI, 1975) that had since been included into a dataset flagged in the database as “USGSBREIT.” All the values reported in this study are identical to those in the database, but the minor constituents are reported in μg/L. Given that the units of the major ions are correct and the number of minor analytes reported are limited, the calculated charge balance may not always be sufficient to screen out this type of error. Therefore, EPA filtered out all minor constituents from USGSBREIT data prior to calculation of summary statistics. For clarity, only the USGSBREIT data was labeled as U.S. DOI (2016) in the E&P Database. Other data for which the original source could be located were incorporated in the E&P Database under that citation and flagged as originating from U.S. DOI (2016) in the notes column. Raw Data: During review of the assembled literature, EPA found that some authors chose to provide summary statistics instead of full datasets. EPA made an initial effort to reach out to a few authors to obtain the underlying data, but received few responses. While summary statistics provide some understanding of the overall distribution of a dataset, it is difficult to incorporate these data along with other individual data points. In particular, the presence of extreme values (e.g., maximum, minimum) can greatly skew analyses. The highest value for one constituent may not correspond to the highest value for another, B1) This database is periodically updated and has been at least once since the E&P database was compiled. The most recent version of the database was not incorporated into the current analysis due to time constraints. However, it is not anticipated to affect the conclusions of this document. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-5 and so extreme values may mask relationships within the data. Therefore, while all of the reported summary statistics were incorporated into the E&P Database, extreme values were filtered out prior from all current analyses. The limited number of mean or median values were incorporated into the analyses as individual data points. When known, the total number of individual samples captured by the summary statistics is also reported in the notes column of the database. Drilling Method: The largest shift in drilling practices in the past several decades has been the adoption of directional drilling in formations previously considered uneconomical to access. The greater consolidation that occurred in these formations trapped the natural gas in isolated small, poorly connected pore spaces that make it difficult to liberate. This consolidation also results in greater evaporation of water from the formation, which may result in higher dissolved constituent levels (concentration and activity) in the remaining water. In addition, the greater distance drilled through high organic and metal shale during horizontal drilling could further concentrate constituent mass in the resulting waste. Therefore, where possible, EPA separated out samples from vertical and horizontal wells for further review and discussion in the main text. Some studies did not specify the orientation of sampled wells and so, unless otherwise specified, EPA assumed all samples collected prior to the year 2000 were from vertical wells. Although horizontal drilling has been an available technology for nearly a century beforehand, it was not in widespread use until the early 2000s (EIA, 2018a). It is known that vertical wells can also be sited in lower-permeability formations and that some are hydraulically-fractured. However, few studies noted whether or not a vertical well had been fractured. Therefore, this remains a source of uncertainty in the dataset. However, the greater tendency for vertical wells to be sited in more permeable formations makes it likely that any differences that exist based on the type of formation will still be apparent in comparisons. The equipment used to install and operate wells may also affect the waste composition. For example, additional constituent mass may be intentionally injected into a well or inadvertently leached from pipes and other equipment in contact with the waste. However, it can be difficult to attribute elevated constituent levels to one of these sources because studies often do not report the specific equipment and practices used at each site. In the case of additives, this information may not be available because it is often claimed as confidential business information (U.S. EPA, 2016b). Yet, even if this information were available, it would be difficult to attribute moderate increases in constituent levels to specific sources without representative samples from wells with and without those sources. In instances where one or more samples were found to be considerably higher than the remaining dataset, EPA reviewed the available information on drilling methods and the available literature to identify and discuss any potential sources. B.1.3 Variability and Uncertainty Variability and uncertainty is the extent to which a literature source effectively characterizes, either quantitatively or qualitatively, these two factors in the procedures, measures, methods or models used. Proper characterization of the major sources of variability and uncertainty provides greater confidence Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-6 that the data are can form the basis for sound conclusions. The data drawn from each literature source is limited in the number of samples or geographical scale. Therefore, no single study can be said to provide a statistically representative sample. However, there is no reason to exclude any individual sample because it does not fully capture the variability of a waste. More data ensures better characterization of the waste types. Therefore, EPA retained data from all of the available studies found to be of sufficient quality. Age of Sampled Waste: The composition of a waste is not always static. For example, water present in hydrocarbon formations often exists under reducing conditions, as well as high temperature and pressure. As a result, the conditions surrounding the water will change dramatically before it can be analyzed in a laboratory. Some of these changes occur rapidly, but others can occur gradually over the days or months that the waste is stored. One example is the gradual transfer of CO2 and O2 between produced water and the atmosphere, which can shift the water pH and result in production of insoluble oxides and carbonates (DOE, 2004). Barium has been shown to precipitate as barite over the course of months, long after the temperature and pressure of the water has equilibrated (Kraemer and Reid, 1984). This precipitate will gradually add to the mass of sludge and scale. Over the same time, organic compounds and radioisotopes in the wastes will degrade through natural processes. Many samples reported in the literature are collected soon after generation; however, E&P wastes can be stored on-site for some time prior to disposal. Studies rarely specify the amount of time that has elapsed since the waste was generated. This type of information may not have been made available to the samplers. In addition, waste generation is an ongoing process and so samples collected from downstream pits and tanks will reflect a mixture of the waste generated over some period of time. This represents a major source of variability and uncertainty that is difficult to address. EPA identified one instance where anomalous data can be attributed to sample age. The comparison of 226Ra and 228Ra activities in produced water found the 228Ra activities reported by Shih et al. (2015) to be low relative to the remaining samples. This study reported secondary data from the Pennsylvania Department of Environmental Protection, which did not provide information on the age of the samples. 228Ra has a predictable half-life (5.8 years), which is far less than the corresponding half-life for 226Ra (1,600 years). Thus, as the sample ages, 228Ra will become depleted relative to 226Ra. Given the isolation of these low values to a single study and the strong correlation observed in the remaining studies, EPA concluded that sample age is the most likely explanation. Therefore, EPA filtered out the samples of 228Ra from this study prior to any analyses. Samples of 226Ra were retained because the much longer half-life eliminates the likelihood of similar issues from decay. Age of Reported Data: The studies identified with relevant characterization data were published over the span of a full century between 1917 and 2017. The oldest studies predominantly sampled produced water that was analyzed only for major constituents (e.g., chloride). These older studies may include samples drawn from formations that are no longer in production. It is possible the wastes from these formations differ from Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-7 those generated today. However, available data show a considerable overlap in the major ion composition of produced water from various states. Thus, while there is some uncertainty associated with older studies, it is believed the data can still provide a reasonable order-of-magnitude estimate of major constituent levels that can be generated by a well. Furthermore, there is an equal amount of uncertainty associated with formations that have yet to be drilled. Therefore, inclusion of data from older formations can help ensure that the range of potential constituent levels is captured in the dataset. Therefore, EPA did not filter out any data solely as a result of the date the study was completed. Sample Collection Location: More than 10,000 new oil and gas wells are drilled each year in the United States (EIA, 2018b). It is not feasible to collect waste samples associated from every well currently in production and so any analysis must aim for a representative subsample. However, some authors do not have the authority to compel sampling and relied on the cooperation of facilities to obtain access to drilling sites. Other authors selected sample locations based on areas known to have elevated constituent levels. As a result, the sample locations reflected in the data are not truly random. This has the potential to bias the reported data, but the extent to which this uncertainty might affect the overall dataset is not known. Another source of uncertainty is the spatial variability of wastes within the sampled pits and tanks. Solids suspended in produced water can settle out quickly once the velocity of the flow slows at the outfall to a pit or tank. This may result in hotspots of some constituents within the management units. Concentrations can also vary based on which piece of equipment is sampled and where. Heavier solids and organics are likely to settle out in equipment early in the production stream, while precipitation is likely to dominate deposition in pits and tanks used for water storage. Although constituent levels may be higher in some areas, it is unknown to what extent this will impact the overall composition of the waste when it is aggregated for disposal. B.3. Data Management Once all of the identified data were assembled in the E&P Database, some additional management steps were taken prior to analyses. The following steps were taken to mitigate sources of variability and uncertainty that could be reliably identified and effectively managed. Charge Balance: Aqueous solutions must be electrically neutral. Thus, the net charge of positive ions (i.e., cations) and negative ions (i.e., anions) must be equal. The charge balance of a solution is the difference between the measured charge of cations and anions in a sample, expressed as a percentage of the total charge. If the calculated charge balance is not zero, it might indicate there was an error during measurement. One potential source of error associated with fluid E&P wastes is high total dissolved solids, which can interfere with measurements if instruments are not properly calibrated. There are a number of reasons why the charge balance calculated for a sample is not exactly zero. A study may not analyze for every constituent that contributes charge or there may be interference from Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-8 other constituents during measurement. Therefore, it is common to calculate the charge balance with a select set of dominant ions and value to a cutoff somewhat higher than zero to determine whether there are concerns about the reported concentrations. EPA selected a cutoff of ±15% for this document based on the previous work in the National Produced Waters Geochemical Database (U.S. DOI, 2016). Prior to any analyses of aqueous wastes, EPA filtered out all samples with a charge balance outside of this range. It is clear that the high charge balance calculated for some studies is primarily the result of the absence of data for one or more of the major ions (e.g., chloride). This was typical when the focus of a study was a specific set of constituents, such as radioisotopes. This does not necessarily mean there are concerns about the quality of these data, but it is not possible to demonstrate otherwise. Therefore, EPA still filtered out any samples that did provide chloride or sodium concentrations, but flagged these samples in the database. Further review found that inclusion of these additional samples did not substantially shift the calculated summary statistics and so these samples are not further discussed in this document. Redundant Data: Some studies reported secondary data drawn from other studies. This has the potential to bias the overall dataset toward samples reported across a greater number of studies. Some studies also do not provide relevant background information for secondary data. Therefore, where possible, EPA obtained and cited to the original source of the data for reference. Any data found to be redundant between two or more studies was removed from the database. In instances where multiple studies provided data for different constituents from the same sample, EPA combined the data from the studies into a single entry in the E&P Database and cited to both studies. To identify redundant data, EPA reviewed the text of each study for citations associated with the reported data. However, some studies did not specify that the reported data was drawn from other studies, particularly in cases where the author(s) built on previous work. To identify this type of redundant data, EPA compared individual samples in the database to identify cases where two or more samples had almost the same value for all of the major ions. To instances where authors rounded exact values. When concentrations were found to be close, other information about the samples was used to confirm that the samples were redundant (e.g., sample date, county). Detection Limits: A detection limit is the lowest quantity or concentration of a constituent that can be reliably detected with a given analytical method. When a constituent is not detected above this limit, the analytical results are typically reported as less than the detection limit because the potential still exists for the constituent to be present at lower levels. Such values are referred to as “left-censored.” The detection limit varies among studies because of differences in the methods used to prepare samples, the sensitivity of analytical instruments, and interference from solid media or other chemical constituents. EPA incorporated all left-censored data in the E&P Database and flagged it with “<” in front of the reported detection limit. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-9 Ideally, left-censored data should be the lowest values in a given dataset. However, there are instances in the database where detection limits are higher than any measured samples. This does not mean that the data are of poor quality. For example, the sequential dilution necessary to analyze highly saline water can result in high detection limits for minor elements. High detection limits introduce a great amount of uncertainty into the evaluation and can bias the overall dataset high. To mitigate this uncertainty, EPA filtered out any non-detect values that greater than the 90th percentile of detected data prior to analysis. This cutoff was selected to strike a balance, as elimination of all non-detect data would only bias the remaining dataset even higher. EPA incorporated the remaining non-detect values using half of the reported detection limit based on the recommendations in Risk Assessment Guidance for Superfund Part A (US EPA, 1989) and with the Guidance on Handling Chemical Concentration Data near the Detection Limit in Risk Assessments (US EPA, 1991). More robust methods are available to manage non-detect data, though these methods often rely on detected data to help backfill censored data, which can be confounded by a small datasets. Therefore, the selected approach is considered reasonable for current purposes of providing a first-order summary of available data. In a few instances, concentrations were reported at higher concentrations than could be measured by analytical instruments. This typically occurred when an element, such as iron or barium, comprised a majority of the mass in samples of drill cuttings, sludge and well scale. EPA incorporated these data in the E&P Database flagged with “>” in front of the reported detection limit. The range of potential concentrations greater than a specified value is typically far wider than those below and so the uncertainty associated with right-censored data is often greater. Therefore, all right-censored data were filtered out prior to any analyses. Given the small number and types of samples with such high concentrations, it was determined that the removal of these samples would not affect the conclusions of this document. Some studies flagged non-detects only as “ND” and did not report the associated numerical detection limit. It is not possible to draw conclusions about likely constituent levels in these samples. EPA incorporated the data as “ND” in the E&P Database to show that the study had analyzed for that constituent. However, these samples were not included in sample counts presented in the main text. Duplicate Samples: Duplicate samples are two or more field samples intended to represent the same source, which are collected and analyzed in a comparable manner. For a number of reasons, such as heterogeneity of the source material and precision of analytical equipment, values measured for these samples may not be identical. EPA treated all samples collected from the same location (e.g., wellhead, storage tank) as duplicates, regardless of whether the samples were collected as part of separate studies or at different times. This was done to avoid biasing the summary statistics towards wells that had been more heavily sampled. Prior to any analysis, EPA averaged all duplicate values for each well. Where duplicates data were a mixture of detect and non-detect values, the non-detect values were set to half the detection limit and averaged along with detected values. The resulting, averaged value was flagged as a detected value for the summary statistics. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-10 One study provided discharge monitoring reports over time (U.S. EPA, 2013). This database includes data for multiple states, but only the data for Wyoming was found to be useful based on the reported analytes. The database included a number of sample collected at different dates, but the samples were not always measured for the same analytes. This would likely cause many of the individual samples to be filtered out as a result of a high charge balance. Further review of the data found that the constituent levels reported over time did not vary dramatically. Therefore, to make best use of the available data and to keep data entry manageable, EPA averaged all of the data reported for a single location prior to incorporating the data in the E&P Database. A few studies reported a large number of samples with many apparent duplicates (U.S. EPA, 2016; U.S. DOE, 2017; U.S. DOI, 2017). However, none of these studies flagged duplicate samples. Instead, EPA inferred the presence of duplicates from other available information, such as well names. These studies did not always maintain consistent reporting for well names and so matching by name would have to be conducted manually. Instead, EPA first matched samples based on GIS coordinates. The resolution of the reported coordinates is unknown and so this approach may combine multiple wells that are located in close proximity, but the uncertainty associated with this error is considered minimal because the wells still reflect the same general region. Where GIS coordinates were not available, EPA manually compared the reported well names and flagged those with similar names (e.g., Well #1 and Well Number One). When neither GIS coordinates or well names were available, samples located in the same county were flagged a duplicates. B.4. Data Summary The current literature review identified over 700 unique studies, of which 228 contained some relevant data that were included in the E&P Database. Each study reported data on a different combination of constituents based on the focus of that individual study. As a result, the total amount of data available for each constituent can be quite variable. Some inorganic constituents were not reported in any of the studies and so are not listed in the database. However, the absence of data does not necessarily indicate these constituents are not present. Conversely, there a large number of organic compounds reported sporadically in the literature that are not included in the database. The limited amount of data for a large number of compounds limits the conclusions that can be drawn from the data. Therefore, EPA focused data collection efforts on benzene, toluene, ethylbenzene and xylene because these compounds are known byproducts of hydrocarbon formation and are the most commonly measured compounds in the literature. EPA chose to provide a qualitative discussion on the magnitude and frequency of detection of other organic compounds. During the review of assembled data, EPA identified multiple major sources of uncertainty. Yet because the range of reported constituent levels varies by orders of magnitude, it can be difficult to distinguish between measurement uncertainty and natural variability. Therefore, EPA did not attempt to define fully representative distributions for any constituent. Instead, the statistics presented in this document are intended only to summarize the available data and allow a more general order-of-magnitude comparison between datasets. Despite the uncertainty associated with the current dataset, EPA Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-11 identified strong trends among the data that indicate the existence of relationships between different constituents that are tied to chemistry and geology, rather than the unique features of individual formations. The likelihood that such strong relationships would erroneously emerge from the noise of numerous independent studies is exceedingly small. Therefore, EPA concludes that the sources of uncertainty in the dataset do not impact the main conclusions in this document and that the data are fit for purpose. Although these data provide useful information for the current discussion, inclusion of a particular study in the database at this stage does not indicate that it will form the basis for future conclusions about waste composition and behavior as more data become available. B.5. References Kraemer, T.F. and D.F. Reid. 1984. “The Occurrence and Behavior of Radium in Saline Formation Water of the U.S. Gulf Coast Region.” Isotope Geoscience. 2:153-174. LADNR (Louisiana Department of Natural Resources). 1999. “TCLP Characterization of Exploration and Production Wastes in Louisiana.” Prepared by D.D. Reible and K.T. Valsaraj of Louisiana State University for LADNR. March. MSC (Marcellus Shale Coalition). 2009. “Sampling and Analysis of Water Stream Associated with the Development of Marcellus Shale Gas.” Prepared by T. Hayes of the Gas Technology Institute. Des Plaines, IL. December. Nelson, A.W., D. May, A.W. Knight, E.S. Eitrheim, M. Mehrhoff, R. Shannon, R. Litman and M.K. Schultz. 2014. “Matrix Complications in the Determination of Radium Levels in Hydraulic Fracturing Flowback Water from Marcellus Shale.” Environmental Science and Technology Letters. 1:204-208. Shih, J., J.E. Saiers, S.C. Anisfeld, Z. Chu, L.A. Muehlenbachs, and S.M. Olmstead. 2015. “Characterization and Analysis of Liquid Waste from Marcellus Shale Gas Development.” Environmental Science and Technology. 49:9557−9565 U.S. DOE (United States Department of Energy). 2004. “Evaluations of Radionuclides of Uranium, Thorium, and Radium Associated with Produced Fluids, Precipitates, and Sludges from Oil, Gas, and Oilfield Brine Injections Wells in Mississippi.” Prepared by C. Swann of the Mississippi Mineral Resources Institute, J. Matthews and J. Kuszmaul of the University of Mississippi, and R. Ericksen under award No. DE-FG26-02NT 15227. March. U.S. DOE. 2017. “Argonne Geothermal Geochemical Database v2.0” [Database]. Prepared by C. Harto of the Argonne National Laboratory. Published on 8/29/17. U.S. DOE. 2018a. “Hydraulically Fractured Horizontal Wells Account for Most New Oil and Natural Gas Well." EIA Today in Energy. Prepared by T. Cook, Jack Perrin and D. Van Wagener of the Energy Information Administration. Published on 1/30/18. U.S. DOE. 2018b. “Crude Oil and Natural Gas Exploratory and Development Wells." [Spreadsheet]. Prepared by the Energy Information Administration. Published on 8/20/2018. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-12 U.S. DOI (United States Department of the Interior). 1975. “Chemical Analyses of Ground Water for Saline-Water Resources Studies in Texas Coastal Plain Stored in National Water Data Storage and Retrieval System – Volume 1.” Open File Series 75-79. Prepared by the United States Geological Survey. Bay St. Louis, MS. March. U.S. DOI. 2016. “U.S. Geological Survey National Produced Waters Geochemical Database v2.2.” [Database]. Prepared by M.S. Blondes, K.D. Gans, M.A. Engle, Y.K. Kharaka, M.E. Reidy, V. Saraswathula, J.J. Thordsen, E.L. Rowan and E.A. Morrissey of the United States Geological Survey. Published on 02/16/16. U.S. DOI. 2017. “Global Geochemical Database for Critical Metals in Black Shales: USGS Survey Data Release” [Database]. Prepared by M. Granitto, S.A. Giles, and K.D. Kelley of the United States Geological Survey. Published on 11/13/17. U.S. EPA (United States Environmental Protection Agency). 1989. “Risk Assessment Guidance for Superfund (RAGS) Part A.” EPA 530-SW-88-002. Prepared by the EPA Office of Emergency Response. Washington, DC. U.S. EPA. 1991. “EPA Region 3 Guidance on Handling Chemical Concentration Data Near the Detection Limit in Risk Assessments.” EPA/903/8-91/001. Region 3. Philadelphia, PA. U.S. EPA. 2002. “Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations.” Prepared by the EPA Office of Solid Waste. Washington, DC. U.S. EPA. 2013. “Technical Development Document for the Coalbed Methane (CBM) Extraction Industry.” EPA-820-R-13-009. Prepared by the EPA Office of Water. Washington, DC. April. U.S. EPA. 2016a. “Wyoming Oil and Gas Conservation Commission (WY OGCC) Water Data Memorandum.” DCN SGE01244. Prepared by J.K. O’Connell and S. Yates of the Eastern Research Group, Inc. for Prepared by the EPA Office of Water. Washington, DC. February. U.S. EPA. 2016b. “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” EPA-600-R-16-236Fa. Prepared by the EPA Office of Research and Development. Washington, DC. December. Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-13 Attachment B-1: E&P Constituent Database [Due to the large file size, this database is maintained as a separate file.] Management of Exploration, Development and Production Wastes Appendix B: Constituent Database B-14 Appendix C: State Programs This appendix provides a summary of the Agency’s review of state programs discussed in Section 6 (State Programs) of the main text. The intent of this review is to better understand how state regulations currently address management of wastes from exploration, development and production operations and to highlight inconsistencies, lack of specificity, or possible gaps in coverage. The following text provides a summary of state programs, broken out into 12 general topic areas and 61 specific elements. The summaries in this appendix are organized by each individual state, presented in order of production (highest to lowest) based on the 2016 production data from the U.S. DOE Energy Information Agency.  Attachment C-1: provides the results of the Agency’s binary (yes/no) determination whether regulations related to each of the 61 regulatory elements are in place for the states reviewed.  Attachment C-2: provides a detailed spreadsheet that contains excerpts from state regulatory text, organized by topic area and with links to the full regulatory text, that form the basis for this review. All links provided in the spreadsheet were active at the time the spreadsheets were compiled. C.1. Texas In 2016, Texas accounted for approximately 32% of the nation’s oil and gas production according to the U.S. Energy Information Agency. It is by far the largest oil and gas producing state in the U.S. with almost three times more production then the second largest producer, Pennsylvania. Because of its long history in oil and gas production, Texas sustains a large amount of conventional production, and continues to pursue conventional reserves, both shallow and deep. Modern shale and tight oil unconventional reserve development began in Texas in the 1990’s and recent discoveries in the Permian Basin suggest that this will be a significant part of future exploration and production. The Oil and Gas Division of the Railroad Commission of Texas (RRC) regulates oil and natural gas production in the state. E&P wastes are regulated by the RRC under a memorandum of agreement with the Texas Commission on Environmental Quality (TCEQ). The Department of Environmental Quality, Land Protection Division is responsible for management of solid waste. NORM related to oil and natural gas production is regulated by RRC under a memorandum of agreement with Texas Department of State Health Services (DSHS). Texas maintains an extensive set of regulations for oil and gas that address a wide range of environmental issues. RRC rules (Title 16, Part 1) include 15 sections including two that address waste management requirements (Oil and Gas Division Rules, Chapter 3, and Environmental Protection, Chapter 4). Chapter 3.8 (Water Protection) contains most of the waste management regulations, and Chapter 4 addresses commercial E&P waste recycling and NORM. Several chapters of the regulations have been updated as recently as 2016; Chapter 3.8 and most of Chapter 4 were most recently updated in 2013. Table C-1 provides a summary of the regulations identified for E&P wastes in Texas. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-1 Table C-1. Summary of Regulations for E&P Wastes in Texas Topic Area Definitions Waste Unit Location Requirements Tank Requirements Summary Section 3.8 includes 47 definitions related to waste and water protection, and more definitions are included within other parts of the rules. The regulations define 16 different types of pits and TRC has grouped the pit regulations by addressing nine types of pits. Additionally, five types of commercial recycle/reuse operations (on and off lease) are addressed in Chapter 4. Regulations pertaining to siting waste management units in floodplains are dispersed in the reserve pit section and all five sections of recycling operations regulations and indicate that “all authorized pits shall be constructed, used, operated, and maintained at all times outside of a 100-year flood plain.” Regulations for surface water and groundwater are overarching and state “No person conducting activities subject to regulation by the commission may cause or allow pollution of surface or subsurface water in the state.” No specific criteria for siting or operation using the term “groundwater” was found. However, throughout the Pit Permit requirements in §3.8 (Water Protection) the director may only issue permits if "the activity does not result in waste of oil, gas, or geothermal resources or pollution of surface or subsurface water." Siting and location requirements related to endangered species are not specifically addressed. The only siting requirements provided in the regulations are a 100-foot setback distance from sensitive areas for commercial recycling plants, and a 150-foot setback from surface water and water supply wells for on-lease commercial waste recycling. Sensitive areas are defined as “by the presence of factors, whether one or more, that make an area vulnerable to pollution from crude oil spills. Factors that are characteristic of sensitive areas include the presence of shallow groundwater or pathways for communication with deeper groundwater; proximity to surface water, including lakes, rivers, streams, dry or flowing creeks, irrigation canals, stock tanks, and wetlands; proximity to natural wildlife refuges or parks; or proximity to commercial or residential areas.” Minimum depth to groundwater for waste units is not specified. TRC regulations do not address many aspects of tanks used for waste management and TCEQ tank regulations (§334.123. (a)(7) Exemptions for Aboveground Storage Tanks (ASTs) exempts oil and gas tanks. General requirements are provided for protection of birds for open-top storage tanks that are eight feet or greater in diameter and contain a continuous or frequent surface film or accumulation of oil. These tanks must be screened, covered or otherwise rendered harmless to birds; however, temporary, portable storage tanks that are used to hold fluids during drilling operations, workovers, or well tests are exempt. Recycling facilities, which may contain tanks, also require bird protections and require design and construction of storage areas, containment dikes and processing areas to prevent pollution of surface and subsurface water. Modular large volume tanks, construction materials, and monitoring are not specifically addressed in the regulations. Permits are required for removal of tank bottoms or other hydrocarbon wastes from any producing lease tank, pipeline storage tank, or other production facility. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-2 Table C-1. Summary of Regulations for E&P Wastes in Texas Topic Area Summary Short term use pits including reserve pits, mud circulation pits, completion/workover pits, basic sediment pits, flare pits, fresh makeup water pits, fresh mining water pits, noncommercial fluid recycling pits, and water condensate pits are authorized by rule and no permit is required when specified conditions in Rule 3.8 are met (also called permit-byrule). Permits are required for longer term storage pits, salt water pits and disposal pits such as saltwater disposal pits; emergency saltwater storage pits; collecting pits; skimming pits; drilling fluid storage pits (other than mud circulation pits); drilling, fluid disposal pits (other than reserve pits or slush pits); washout pits; and gas plant evaporation/retention pits. Pits associated with certain recycling facilities are included as part of the facility permits. Storage of oil in pits of any type is prohibited. Pit Construction and Operation Requirements Design and construction requirements for permit-by-rule pits are not explicitly defined in most pit regulations. Only non-commercial fluid recycling pits include specifications. For these pits, liner materials may vary and must have a permeability less than 1×10-7 cm/sec. For permitted pits requirements such as dike design, minimum depth to groundwater, liner material and thickness, schedules, and fences, are specified in the permits. In addition, skimming pits and collecting pits must be screened, covered or otherwise rendered harmless to birds. General freeboard and berm requirements are provided for non-commercial fluid recycling pits stating that “All pits shall be sufficiently large to ensure adequate storage capacity and freeboard taking into account anticipated precipitation.” and “All pits shall be designed to prevent stormwater runoff from entering the pit. If a pit is constructed with a dike or berm, the height, slope, and construction material of such dike or berm shall be such that it is structurally sound and does not allow seepage.” Signs are required for the general well location and are not pit specific. Inspections and groundwater monitoring are required for commercial recycle/reclamation pits, brine pits, and as specified in a permit. Permits and leak detection/monitoring are required for brine pits only. Discharge from pits requires a letter of request but no application or permit is necessary. Centralized pits are not specifically addressed in the regulations, but they may fall under non-commercial fluid recycling pits located offsite. Pit Closure Requirements Most drilling fluids and cuttings can be disposed in the original pit by burial. Liquids removal is required prior to pit closure for high chloride fluids. Completion and workover wastes (including fluids and solids) can be buried on site in their original pits, as can solids generated from non-commercial recycling pits. The closure schedule varies depending upon pit type, and details are provided in the regulations. Generally, drilling pits must be backfilled and compacted within one year, and all other pits (completion, workover, basic sediment and others) must be backfilled within 120 days. Liners for non-commercial fluid recycling pits must be inspected annually by the operator unless a double liner with leak detection is used. Storage areas for commercial recycling/reclamation pits must be inspected as indicated by permit. Sampling is necessary for stationary solid waste recycling facilities, waste separation facilities, reclamation facilities, or as specified by permit. For wells, financial security is not pitspecific but rather provided by the general APD bond. Financial security bonds are required for all five categories of recycling facilities in Chapter 4. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-3 Table C-1. Summary of Regulations for E&P Wastes in Texas Topic Area Spill Notification Corrective Action Off-site Landfills Land Application Summary Unpermitted discharge from any pit requires the operator to take any measures necessary to stop or control the discharge and report the discharge to the district office as soon as possible. For other waste management units (tanks) immediate notification of a fire, leak, spill or break is required followed by a letter giving the full description of the event, and the volume of crude oil, gas, geothermal resources, other well liquids, or associated products lost. Response actions for crude oil and condensate releases are addressed in the regulations, but the corrective action process for exempt wastes is not described in the regulations. According to the Memorandum of Understanding between RRC and TCEQ, RRC is solely responsible for the control and disposition of waste and the abatement and prevention of pollution of surface and subsurface water in the state from activities associated with the exploration, development, and production of oil and gas. RRC Cleanup Orders appear to be used to identify actions and timelines for remediating releases of waste. Disposal of E&P waste is allowed in offsite pits and require a permit. Commercial pits require testing of waste and groundwater monitoring wells. Disposal of exempt waste in municipal solid waste landfills is not discussed in the regulations but appears to be allowed with concurrence from TCEQ (TXCEQ, 2014). Use as daily cover is not specifically addressed in the regulations. Land application (landfarming) of E&P waste on-lease property is allowed for low chloride muds and cuttings and does not require a permit (considered permit-by-rule). Other than the chloride content, there are no specific limitations/conditions for landfarming. Offlease application requires a disposal permit, which includes site specific limitations/restrictions for use. Non-commercial recycling or reuse of treated fluid is allowed and does not require a permit. Commercial recycling facilities are subject to location and operating conditions provided in the regulations and facility permit. Beneficial Use Waste Minimization/ Management Beneficial use of basic sediment is allowed for application to lease roads, and a permit is required for off-lease applications only. Roadspreading of brine does not appear to be explicitly allowed under the regulations, but the RRC has flexibility to approve applications for alternate disposal and use of brine. Disposal of oil and gas NORM waste on roads is prohibited. Waste minimization practices, such as closed loop drilling and mandatory recycling of produced water are not specifically addressed in the regulations. The RRC Waste Minimization Guide and guidance on the RRC website encourage the reduction, reuse and recycling of wastes. RRC Chapter 4 presents the regulations for five different types of commercial recycling facilities including: Commercial Recycling and Reclamation Facilities  On-Lease Commercial Solid E&P waste Recycling Facilities  Off-Lease Commercial Solid E&P waste Recycling Facilities  Stationary Commercial Solid E&P waste Recycling Facilities  Off-Lease Commercial Recycling of Fluid  Stationary Commercial Recycling of Fluid Regulations for each facility type are addressed in the regulations and all require permits and financial security. Many of the technical specifications are contained in the operating permits, which are based on information provided during the permit application process. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-4 Table C-1. Summary of Regulations for E&P Wastes in Texas Topic Area NORM and TENORM C.2. Summary Oil and gas NORM waste is regulated in Texas by RRC under memorandum of agreement with DSHS, and such waste is addressed in the oil and gas regulations. Testing of NORM wastes is required prior to disposal, which may include burial at generation location or landfarming if waste does not exceed 30 pCi/g Radium-226 combined with Radium-228 or 150 pCi/g of any other NORM radionuclide. Off-site disposal and injection are also options for NORM. Pennsylvania In 2016, Pennsylvania accounted for approximately 11.5% of the nation’s oil and gas production according to data provided by the U.S. Energy Information Agency. Much of the production is from unconventional reserves in the Marcellus (beginning around 2003), and the remaining is from shallower conventional wells associated with oil and gas producing intervals since the mid 1800’s. In 2017, a total of 2,028 unconventional permits were issued and 203 conventional permits were issued (PADEP, 2018). Part of Pennsylvania is underlain by the Utica Shale, which is a potential target for future unconventional oil and gas production. The Office of Oil and Gas Management in Pennsylvania’s Department of Environmental Protection (PADEP) regulates oil and natural gas production in the state. The PADEP also regulates solid and hazardous wastes. NORM/TENORM is not specifically addressed in state oil and gas regulations. Pennsylvania substantially updated its E&P regulations by adding Chapter 78a to address unconventional wells in 2016. The new section provides more stringent requirements for many waste management activities including pits, modular tanks and centralized pits. Table C-2 provides a summary of the regulations identified for E&P wastes in Pennsylvania. Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania Topic Area Definitions Summary Approximately 150 definitions are provided between Chapters 78 and 78a of the regulations; some appear in both chapters. Pits are defined generally, but specific types are not defined or addressed in the regulations. Text in the regulations note that pits are temporary, and pit and tank contents may include wastes generated from drilling, altering, completing, recompleting, servicing and plugging the well including brines, drill cuttings, drilling muds, oils, stimulation fluids, well treatment and servicing fluids, plugging and drilling fluids. Regulations regarding oil and gas activities distinguish the drill cutting type based on origination, either from above the surface casing seat (uncontaminated drill cuttings, tophole water or fresh water) or below the surface casing seat (contaminated drill cuttings and associated fluids). Management of Exploration, Development and Production Wastes Appendix C: State Programs C-5 Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania Topic Area Waste Unit Location Requirements Tank Requirements Summary Regulations regarding protection of floodplains, surface water and groundwater are dispersed throughout the various technical regulations for pits, tanks and other activities. An analysis of the well’s impact on endangered species is required in the permit application and endangered species are mentioned in the pipeline planning regulation.C1 Location restrictions are provided (for example, pits shall not be located within 100 feet of a stream, body of water or wetland, or within 200 feet of a water supply). In addition, wastes from below the casing seat (potentially contaminated with oi and gas fluids) may not be disposed or land applied within 200 feet of an existing building. Regulations for tanks refer to requirements under 40 CFR Part 112. Signs are required at tank batteries, and at least 2 feet of freeboard is necessary for all open tanks or storage structures. While specific construction materials are not specified, the container must be impermeable to contain the regulated substances which are used or produced during drilling, altering, completing, recompleting, servicing and plugging the well. Modular large volume tanks are addressed in the regulations, and those that exceed 20,000-gallon capacity need prior Department approval. A permit is required for removal of tank bottoms. Tank monitoring and netting requirements are not specifically addressed in the regulations. Open top structures are not allowed for storage of produced fluids (brine and hydrocarbons). Because the tank rules reference 40 CFR Part 112, federal requirements for construction and operation may apply. Pit Construction and Operation Requirements C1) Pit contents recognized in the regulations include a wide range of wastes generated from drilling, altering, completing, recompleting, servicing and plugging the well including brines, drill cuttings, drilling muds, oils, stimulation fluids, well treatment and servicing fluids, plugging and drilling fluids. Pits require a permit and may not be used for temporary storage. A distinction is made between (1) pits used for uncontaminated drill cuttings from above the casing seat, tophole water (generated from drilling the shallow portion of the hole) and fresh water and (2) pits used to contain drill cuttings from below the casing seat, pollutional substances, wastes or fluids other than tophole water, fresh water and uncontaminated drill cuttings. Pits for contaminated drill cuttings or fluids other than tophole or fresh water have more stringent requirements, such as a synthetic liner or an alternative material (if approved by the Department) and the bottom of the pit shall be at least 20 inches above seasonal high groundwater table. § 78a.68. Oil and gas gathering pipelines also includes associated facilities which may consist of pigging stations, drip pits and compressor stations which may handle or store exempt E&P wastes. The regulation requires flagging of endangered species habitat prior to land clearing. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-6 Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania Topic Area Pit Construction and Operation Requirements (Cont.) Summary Fencing is required for well development impoundments only and not pits specifically, although a well development impoundment is functionally equivalent to a pit. Berm requirements are specified for well development impoundments at unconventional wells and produced fluids containment at conventional wells. Regulations also address signage, inspections, temporary pit requirements, and run-on/run-off controls. Groundwater monitoring does not appear to be required for wells or specific waste management units. However, the regulations imply that water quality data from preconstruction monitoring at centralized impoundments is required. State guidance notes that under PA Act 13 (2012 improvements to oil and gas laws) there is a presumption of liability for contamination of private water supply wells within 2500 feet of oil and gas wells. While the regulations have no requirement for pre-drill sampling, they put the onus on oil and gas industry for groundwater monitoring at nearby water supplies. Onsite processing of wastes at noncommercial fluid recycling pits is allowed for beneficial use only. Centralized pits at unconventional wells require a permit. Regulations do not address leak detection or monitoring or netting of pits. Pit Closure Requirements Conventional well regulations allow closure of lined pits in place and specify liquids must be removed prior to backfilling of the pit. A permit may be required. Remaining contaminated drill cuttings (defined as residual waste) must be encapsulated in the liner and folded over (or an additional liner added). Regulations also require covering the waste prior to backfilling with at least 18 inches of soil. Cuttings from unconventional wells cannot be disposed in pits without approval of the director and in compliance with regulations for management of residual wastes. Pits containing production fluids must be closed within 9 months after completion of drilling. Pits used during servicing, plugging and recompleting a well shall be closed within 90 days of construction. Regulations state that inspections of wells with onsite brine disposal or residual waste are intended to be inspected at least once per year. Bonds are required for wells, but there are no financial security requirements for pits or other waste management units. The owner/operator shall notify the appropriate regional office of the Department as soon as practicable (but no later than 2 hours) after detecting or discovering a reportable release of brine on or into the ground at the well site. A reportable release of brine is defined as “spilling, leaking, emitting, discharging, escaping or disposing of one of the following: (i) More than 5 gallons of brine within a 24-hour period on or into the Spill Notification ground at the well site where the total dissolved solids concentration of the brine is equal or greater than 10,000 mg/l. (ii) More than 15 gallons of brine within a 24-hour period on or into the ground at the well site where the total dissolved solids concentration of the brine is less than 10,000 mg/l.” Unconventional wells: Notification is required as soon as practicable but no later than 2 hours after discovering the following spills/releases at unconventional well sites: (1) spills or releases of a regulated substance causing or threatening pollutions of the Commonwealth or (2) spills or releases of 5 gallons or more of a regulated substance over a 24-hour period that is not completely contained by secondary containment. The operator or other responsible party shall take necessary interim corrective actions, identify and sample water supplies that have been polluted or threatened. Temporary emergency storage or transportation methods may be approved by the Department. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-7 Table C-2. Summary of Regulations for E&P Wastes in Pennsylvania Topic Area Summary “Upon the occurrence of any release, the owner or operator shall take necessary corrective actions to: (1) Prevent the substance from reaching the waters of this Commonwealth. (2) Recover or remove the substance which was released. (3) Dispose of the substance in accordance with this subchapter or as approved by the Department.” (78.66 - https://www.pacode.com/secure/data/025/chapter78/025_0078.pdf) Corrective Action Unconventional wells: “Remediation of an area polluted by a spill or release is required. The operator or other responsible party shall remediate a release in accordance with the following: (1) Spills or releases to the ground of less than 42 gallons at a well site that do not pollute or threaten to pollute waters of the Commonwealth may be remediated by removing the soil visibly impacted by the spill or release and properly managing the impacted soil in accordance with the Department’s waste management regulations. The operator or responsible party shall notify the Department of its intent to remediate a spill or release in accordance with this paragraph at the time the report of the spill or release is made. (2) For spills or releases to the ground of greater than or equal to 42 gallons or that pollute or threaten to pollute waters of the Commonwealth, the operator or other responsible person must demonstrate attainment of one or more of the standards established by Act 2 and Chapter 250 (relating to administration of Land Recycling Program).” (78a.66 - https://www.pacode.com/secure/data/025/chapter78a/025_0078a.pdf) Off-site Landfills E&P waste disposal is allowed at municipal solid waste landfills that are permitted to accept the waste. Testing of waste and its use as daily cover are not specifically addressed in the regulations. Land Application Drill cuttings may be land applied, however, specifications vary depending on whether the materials originate from above or below the casing seat, and a permit is required. Requirements for land application are detailed and address contaminants, distance from sensitive receptors, soil thickness, percolation controls (frozen ground and free liquid content), loading and application rate, and revegetation requirements. Tophole water or water in a pit as a result of precipitation may not be land applied unless specific water quality requirements are met. Beneficial Use Regulations state that production brines from unconventional wells may not be used for dust suppression, road stabilization, pre-wetting, anti-icing and de-icing. Conventional well regulations are moot on the application of brines to roads (roadspreading) but a 2011 PA DEP fact sheet states “DEP considers roadspreading of brine for dust control and road stabilization to be a beneficial use of the brine.” And further explains that brines from shale gas formations are not allowed to be used. The fact sheet outlines seven components of a plan that must be addressed prior to receiving a permit for beneficial use. Road spreading is strictly controlled and subject to 14 operating requirements relating to rate and frequency, sources of brine, chemical composition and presence of contaminants, proximity to water sources and sensitive receptors, spreading equipment, road conditions and monthly reporting. Waste Minimization/ Management Regulations do not specify closed loop drilling, but pits are not allowed for unconventional well drilling, therefore it assumed that closed loop or pitiless drilling is required. Produced water recycling is not required. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities for water or cuttings are not specifically addressed in these regulations. NORM and TENORM State regulations do not address NORM/TENORM. Radiation testing is required for disposal at off-site municipal landfills but not for NORM/TENORM specifically. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-8 C.3. Alaska Alaska accounted for approximately 8.4% of the nation’s oil and gas production in 2016, all from conventional resources, according to the U.S. Energy Information Agency. The Alaska Oil and Gas Conservation Commission within the Department of Administration regulates oil and gas production and facilities. Solid and hazardous waste are regulated by the Alaska Department of Environmental Conservation, Division of Environmental Health. NORM/TENORM is not specifically addressed in state oil and gas regulations. Many oil and gas and solid waste regulations were updated in 2017, in particular regulations regarding drilling waste disposal. Table C-3 provides a summary of the regulations identified for E&P wastes in Alaska. Table C-3. Summary of Regulations for E&P Wastes in Alaska Topic Area Definitions Waste Unit Location Requirements Summary E&P regulations contain 77 definitions, but few are related to the waste management processes. Pits are not included in the definitions and only reserve pits are mentioned by name/use in these regulations. There are no specific siting or location requirements for waste management facilities associated with drilling, completion and production facilities. Solid waste regulations related to siting and locations are dispersed throughout the rules for drilling waste landfills and include general operating requirements to not impact surface water or groundwater. Endangered species are not specifically addressed in these regulations. The only setback specified is for a new landfill or expansion of an existing landfill that may not be constructed within 500 feet of a drinking water supply well. Tank Requirements Pit Construction and Operation Requirements Regulations refer to API standards for construction, including steel and fiberglass. Tank monitoring requires an external gage or catchment/sump. No other tank requirements are included in these regulations; modular large volume tanks, netting, tank monitoring and tank bottom removal are not specifically addressed. All drilling pits (including completion and production pits) are considered drilling waste temporary storage facilities and are included under the solid waste regulations. Permits are not required for pits, but a drilling waste storage plan is necessary as part of the well permitting process, and requires information on the location, construction specifications operational practices, and ultimate disposal location of the wastes. Reserve pits for the confinement of drilling fluids and cuttings are the only type of pit mentioned by name/use. Reserve pits have few requirements other than to be properly sized and impervious. Liners for temporary pits are required and must be made of flexible geomembrane (30 or 60 mils thick) that is compatible with petroleum. Precipitation should be included in the design to ensure that a minimum freeboard of 2 feet is maintained, and confinement dikes should be avoided or kept to a minimum; pit construction must ensure integrity. Run-on/run-off control measures are not specified for pits but indicate that runoff from landfills should not be polluted run-off water. Signs are required for wells and drill waste landfills but not pits specifically. Pit requirements are not provided for leak detection/monitoring, fencing, netting, depth to groundwater, groundwater monitoring, inspection, non-commercial fluid recycling pits or centralized pits. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-9 Table C-3. Summary of Regulations for E&P Wastes in Alaska Topic Area Summary Pit Closure Requirements Pit closure consists of a general requirement that upon completion the operator shall proceed with diligence to leave the reserve pit in a condition that does not constitute a hazard to freshwater. A visual site inspection must be conducted to verify that all drilling waste has been removed. Financial security for pits is included in the general well bonding. Spill Notification Spill notification is not specifically addressed in the state regulations. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills Drilling waste monofills are specified in the solid waste regulations. General requirements allow for only RCRA-exempt wastes (Footnote: the citation date “40 C.F.R. 261.4(b)(5), revised as of July I, 1998” appears to be incorrect). Regulations specify design standards including liners, freeboard, protection of surface water and groundwater, and maintain integrity. Visual and groundwater monitoring is required. Drilling waste landfills in permafrost areas must be designed and monitored to protect the permafrost. Closure of the landfill requires removal of liquids, capping and post closure care requirements (deed notice and visual monitoring for 5 years). Testing and use of waste as a daily cover in municipal solid waste landfills are not specifically addressed. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use of drill cuttings may be allowed by special request/approval. Waste Minimization/ Management Waste minimization and management activities, such as closed loop drilling and produced water recycling, are not specifically addressed in these regulations. Commercial recycling and reclamation facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in the state regulations. NORM and TENORM NORM and TENORM are not specifically addressed in the state regulations. C.4. Oklahoma In 2016, Oklahoma accounted for approximately 7.3% of the nation’s oil and gas production according to the U.S. Energy Information Agency. Oil and gas production come from conventional resources (shallow vertical wells) that have been producing since the early 1900’s and several recent unconventional resources play across the state.C2 In 2016, about 20% of the completed wells were from conventional reservoirs. The Oil and Gas Division within the Oklahoma Corporation Commission regulates oil and natural gas production in the state. The Department of Environmental Quality, Land Protection Division is responsible for management of solid waste. NORM/TENORM is not specifically addressed in state oil and gas regulations. C2) A play is an area in which hydrocarbon accumulations or prospects of a given geologic type occur. A play may comprise many different fields or may be a continuous accumulation of oil and gas across a large area. Examples: Marcellus, Utica, Mississippi Lime, Eagle ford and others. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-10 Oil and Gas Conservation regulations (Title 165, Chapter 10) include 19 chapters and are regularly updated. Sections of the Drilling regulations (Chapter 3) Pollution Abatement regulations (Chapter 7), Commercial Recycling (Chapter 8) and Commercial Disposal (Chapter 9) regulations have been updated in 2013, 2015 and 2017. Regulations provide specifications and requirements, and also allow the OCD to approve alternative approaches by operators. Table C-4 provides a summary of the regulations identified for E&P wastes in Oklahoma. Table C-4. Summary of Regulations for E&P Wastes in Oklahoma Topic Area Definitions Summary Approximately 130 definitions are provided in the general provisions for oil and gas operations (Title 165, Chapter 10). Multiple pit types are defined, including commercial pits, completion/fracture/workover pits, emergency pits, noncommercial pits, off-site reserve pits, recycling/reuse pits, remediation pits and reserve/circulation pits. Other terms including “truck wash pit” and “deleterious substances” are defined.C3 Land farming is referred to as soil farming in the regulations. Regulations pertaining to floodplains, surface water and groundwater are dispersed throughout the drilling and pollution abatement sections, while regulations for endangered species are overarching and only included as notices to operators that they must comply with federal statutes, such as the Bald Eagle Protection Act and the Migratory Bird Treaty Act. Waste Unit Location Requirements Tank Requirements Siting requirements are provided for noncommercial pits, commercial pits, and commercial facilities, including landfarming and recycling facilities. Requirements vary from general (pits and facilities must be constructed such that contents will not be harmful to groundwater, surface water, soils, plants or animals) to specific (for example, noncommercial pits, commercial pits, and commercial landfarming or recycling facilities may not be constructed within a 100-year floodplain). Residential setback is not specified in these regulations. Minimum depth to groundwater requirements are 25 feet for pits and other waste facilities. General requirements are provided for tanks. Examples include “protection of migratory birds” for open tanks, and they should be “constructed and maintained so as to prevent pollution.” Detailed specifications are not provided. Crude oil tanks (which may include tank bottoms) also fall under general requirements such as “Oil storage tanks shall be constructed so as to prevent leakage. Dikes or retaining walls, where necessary, shall be constructed, based on tank capacity and throughput, so as to prevent oil or deleterious substances from causing pollution and to ensure public safety.” While tank bottom removal permits are not required for tanks managed by operators, they are required for commercial tank bottom reclamation facilities. Modular large volume tanks, tank berms and containment, and monitoring and are not specifically addressed in the regulations. C3) Deleterious substance is a key waste term in the Oklahoma regulations covering a wide range of materials and wastes. It includes any chemical, salt water, oil field brine, waste oil, waste emulsified oil, basic sediment, mud, or injurious substance produced or used in the drilling, development, production, transportation, refining, and processing of oil, gas and/or brine mining. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-11 Table C-4. Summary of Regulations for E&P Wastes in Oklahoma Topic Area Summary Construction and operation requirements are provided for noncommercial pits, which include completion, fracture, and workover pits, emergency pits, recycling/reuse pits, spill containment pit, remediation pits and reserve/circulation pits. Permits are required for such pits. Liner requirements vary for noncommercial pits, including reserve/circulation and/or completion/fracture/workover pits. The requirements are determined by the Commission’s Technical Services Department and depend upon soil and fluid characteristics for each well site. The site will be classified to require one of five categories of containment (liner systems) ranging from unlined to geomembrane liners. Details for each category is provided in the regulations. In addition, emergency pits are not required to be lined, and basic sediment pits must have a geomembrane liner. Fencing is required for commercial pits and noncommercial brine disposal and flowback water pits but are not required for reserve and circulation pits. Requirements for netting refer to federal statutes. Pit Construction and Operation Requirements Freeboard requirements range from 6 inches to 3 feet depending on the pit construction and contents, and pits constructed to not receive runoff water. Requirements for minimum depth to groundwater, berm construction, and signage are also provided. Offsite reserve pits and recycling require signs, but pits associated with well sites only require general lease signs. Flowback water pits with capacity of 50,000 bbl. (either onsite or offsite) require signage. Groundwater monitoring is necessary for brine disposal well pits and flowback pits with capacities greater than 50,000 barrels. Inspections are only specified for flowback water pits. OCD is required to inspect all reserve and circulation pits in the special rule areas of Atoka, Pittsburg and Coal counties Discharge permits are required for produced water and hydrostatic test/storm water with elevated constituents. Saltwater disposal pits and flowback pits are defined as temporary storage and require permits. Non-commercial fluid recycling pits and centralized pits (only for recycling and reuse of drilling mud) are also addressed in the regulations. Pit Closure Requirements Liquids removal is required prior to pit closure, and multiple options for solids are allowed including on site burial with or without stabilization and offsite disposal. Closure in place requires minimum of three feet of soil cover and erosion control. The closure schedule is provided in the regulations and depends upon the pit category or type/contents. Most pits, including all reserve/circulation and flowback water pits must be closed within three to 12 months, but flare and spill pits must be closed within 30 days, and basic sediment pits must be closed within 60 days. Inspection, sampling and financial security are all required for closure of pits. Spill Notification Nonpermitted discharges require verbal reporting within 24 hours of discovery of (i) Any non-permitted discharge of deleterious substances of ten barrels or more (single event) to the surface; or (ii) Any discharge of a deleterious substance, regardless of quantity, to the waters of the State. A written report shall be filed within 10 business days. Corrective Action The Pollution Abatement regulations refer to cleanup practices and requirements addressed in the general practices appearing in the Oil and Gas Conservation Division's Guardian Guidance document. The guidance is a step by step methodology containing numerical and risk based cleanup approaches. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-12 Table C-4. Summary of Regulations for E&P Wastes in Oklahoma Topic Area Off-site Landfills Summary Disposal of E&P waste at offsite landfills is not specified in the regulations but rather based on Department of Environmental Quality approval or landfill permit requirements, and testing is required prior to disposal. Use of waste as daily cover is not specifically addressed in the regulations. Land Application Water-based fluids and/or drill cutting from earthen pits and tanks may be land applied with a permit. Land restrictions (such as a maximum slope of 8% and minimum depth to bedrock of 20 inches) are provided in the extensive set of regulations. Sampling requirements and limitations/conditions for application are also included. Details and conditions for commercial soil farming are also included. Beneficial use of brine (reuse and recycling) is allowed but details are not included in regulations. Beneficial Use Roadspreading is not allowed. However, the regulations allow waste oil, residue and crude oil contaminated soil to be applied to lease roads and county roads with a permit. According to the table of allowable uses, drill cuttings from freshwater and oil-based muds can be applied to lease roads also. Waste Minimization/ Management Waste minimization practices, such as closed loop drilling and recycling of produced water, are not specifically addressed in the regulations. Commercial Recycling and Reclamation Facilities Subchapter 9 of Title 165, Chapter 10 addresses commercial disposal facilities, including pits, soil farming, disposal well surface facilities, and recycling facilities. Detailed requirements, including permitting, construction, financial security, and sampling/monitoring are provided for each commercial facility type. NORM and TENORM NORM and TENORM are not specifically addressed in state regulations. C.5. North Dakota In 2016, North Dakota accounted for approximately 6% of the U.S. oil and gas production as indicated by U.S. Energy Information Agency data. E&P wastes generated in North Dakota are regulated by the Industrial Commission of North Dakota, Division of Oil and Gas. Off-site waste disposal and TENORM are regulated under the North Dakota Department of Health, Solid Waste Management and Land Protection. Oil and gas regulations are amended frequently, including several updates in 2012, 2014, and 2016, which addressed fencing, drilling pits and reserve pits, in addition to other topics. Updated solid waste TENORM rules became effective in 2015. Table C-5 provides a summary of the regulations identified for E&P wastes in North Dakota. Table C-5. Summary of Regulations for E&P Wastes in North Dakota Topic Area Definitions Summary The General Oil and Gas Rules and Regulations (Chapter 43-02-03) provide 52 general definitions including “occupied dwelling” (lived in by a person at least six months in a calendar year). The term “saltwater handling facility” is a broad definition that appears to include any container or site used for handling storage or disposal throughout the drilling, completion and production phases. Definitions of pit types defined in the regulations include reserve pit, earthen pits/open receptacles, and drilling pits. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-13 Table C-5. Summary of Regulations for E&P Wastes in North Dakota Topic Area Waste Unit Location Requirements Summary General location standards are provided for solid waste facilities, not E&P waste facilities specifically. For example, no solid waste management facility may be located in areas which result in impacts to human health or environmental resources or in an area which is unsuitable because of reasons of topography, geology, hydrology, or soils. Solid waste regulations contain more specific requirements; for example, solid waste facilities are not allowed within a one hundred-year floodplain or in areas designated as critical habitats for endangered or threatened species of plant, fish, or wildlife. Oil and gas regulations provide general requirements for siting. Drilling pits shall not be located in, or hazardously near, bodies of water. Saltwater handling facilities and treating plants shall be sited in such a fashion that they are not located in a geologically or hydrologically sensitive area. There are no specific setback requirements for E&P waste management facilities. Tank Requirements Produced water tanks and saltwater handling facilities require dikes when deemed necessary by the director. Dikes must be constructed of sufficiently impermeable material to provide emergency containment. Tank monitoring and netting for open tanks are not specifically addressed. The director may permit portable-collapsible receptacles used solely for storage of fluids used in completion and well servicing operations, although no flowback fluids may be allowed. Regulations in North Dakota cover and require permits for the following pit types: reserve pit, earthen pit/open receptacle, and drilling pits. Unlined earthen pits for saltwater, drilling mud, crude oil, waste oil, or other wastes are prohibited, except in an emergency and upon approval by the director. The director may permit pits or receptacles used solely for the purpose of flaring casinghead gas. Pits for treatment plants and saltwater facilities are prohibited unless authorized by an appropriate regulatory agency. Regulations allow for less stringent pit and disposal requirements for shallow wells using freshwater muds. Pit Construction and Operation Requirements Limited details are provided for pit construction and operation. Liners are mentioned but no details are included (for example, “A lined earthen pit or open receptacle may be temporarily used to retain oil, water, cement, solids, or fluids generated in well plugging operations…Freshwater pits shall be lined and no pit constructed for this purpose shall be wholly or partially constructed in fill dirt unless approved by the director”). Fencing is required for open pits and ponds that contain saltwater or oil and is not required for drilling or reserve pits used solely for drilling, completing, recompleting or plugging except after 90 days or unless indicated by the director. All pits and ponds that contain oil must be fenced, screened and netted. Berm specifications are general for drilling pits (“shall be diked in a manner to prevent surface water from running into the pit”) while berms for saltwater handling facilities are more specific (for example, height requirements and must be constructed of “sufficiently impermeable material”). At saltwater handling facilities and treating plants, waste, recovered solids, and fluids must be stored and handled in such a manner to prevent runoff or migration offsite. Signage is required for freshwater pits, as well as portable-collapsible receptacles. Drilling pits require inspection by an authorized representative of the director prior to lining and use. Inspection was not noted for other types of pits. Monitoring plans and leak detection, which may include groundwater monitoring, are necessary for all buried and partially buried structures at treatment plant facilities. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-14 Table C-5. Summary of Regulations for E&P Wastes in North Dakota Topic Area Pit Construction and Operation Requirements (Cont.) Summary Regulated pits may be used temporarily to (1) retain oil, water, cement, solids or fluids generated during well plugging operations containment, or (2) contain incidental fluids such as trench water and rig wash. Flare pits are considered temporary. Noncommercial fluid recycling pits are not specifically prohibited or allowed, however saltwater handling and disposal operations or fluid and tank bottom treatment at the well site which typically recover skim oil from their operations, is permitted. Central production facilities and centralized tank batteries are discussed but centralized pits are not specifically addressed. Freeboard requirements, minimum depth to groundwater, and discharge permits are not specifically addressed in the regulations. Liquids removal is required for closure of drilling, reserve and temporary pits. The contents of an earthen pit or receptacle must be removed within seventy-two hours after operations have ceased and must be disposed of at an authorized facility. Drilling waste in reserve and drilling pits should be encapsulated in the pit and covered with at least four feet [1.22 meters] of backfill and topsoil and surface sloped, when practicable, to promote surface drainage away from the reclaimed pit area. Pit Closure Requirements Pits shall be reclaimed within 30 days after operations have ceased (earthen pit) or within 30 days after the drilling of a well or expiration of a drilling permit (drilling pit). Reserve pits shall be closed within a reasonable timeframe but not more than one year after the completion of a shallow well, or prior to drilling below the surface casing shoe on any other well. Prior to reclaiming a drilling pit, the operator or the operator's agent shall obtain verbal approval from the director of a pit reclamation plan. Financial security for pits is not required but is included as a part of the overall well permit bond. Spill Notification The operators or responsible parties shall verbally notify the director immediately and follow up utilizing the online initial notification report within twenty-four hours after discovery of any fire, leak, spill, blowout, or release of fluid. The commission, however, may impose more stringent spill reporting requirements if warranted by proximity to sensitive areas, past spill performance, or careless operating practices as determined by the director. Corrective Action For spill cleanup, discharged fluids must be properly removed and may not be allowed to remain standing within or outside of diked areas. Operators and responsible parties must respond with appropriate resources to contain and clean up spills. Off-site Landfills North Dakota Administrative Code Section 43-02-03-19.2 states in part that all waste material associated with exploration or production of oil and gas must be properly disposed of in an authorized facility in accord with all applicable local, state, and federal laws and regulations. This includes filter socks and other filter media but does not require the offsite disposal of drilling mud from shallow wells or drill cuttings associated with the drilling of a well. Effective June 1, 2014, a container must be maintained on each well drilled in North Dakota to store filters until they can be properly disposed of in an authorized facility. Testing of waste prior to disposal and use of E&P waste as daily cover are not specifically addressed in the regulations. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in the state regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-15 Table C-5. Summary of Regulations for E&P Wastes in North Dakota Topic Area Summary Saltwater handling facilities and treating plants are regulated, and a bond is required for these facilities. The operator of a saltwater handling facility [or treating plant] shall provide continuing surveillance and conduct such monitoring and sampling as the commission may require. An offsite reclamation manifest is also required. Commercial Recycling and Reclamation Facilities “’Treating plant’ means any plant permanently constructed or portable used for the purpose of wholly or partially reclaiming, treating, processing, or recycling tank bottoms, waste oils, drilling mud, waste from drilling operations, produced water, and other wastes related to crude oil and natural gas exploration and production. This is not to be construed as to include saltwater handling and disposal operations which typically recover skim oil from their operations, treating mud or cuttings at a well site during drilling operations, or treating flowback water during completion operations at a well site.” “’Saltwater handling facility’ means and includes any container and site used for the handling, storage, disposal of substances obtained, or used, in connection with oil and gas exploration, development, and production and can be a stand-alone site or an appurtenance to a well or treating plant.” Disposal of TENORM is allowed at a licensed facility, and storage requirements are provided. Limitations include (1) TENORM waste up to, but not exceeding 50.0 picocuries per gram of Radium-226 plus Radium-228, and (2) equipment contaminated with TENORM which does not exceed a maximum exposure level of one hundred microroentgen per hour, including background radiation. NORM and TENORM Landfill requirements for TENORM disposal include a composite liner (at least three feet [91.4 centimeters] of recompacted clay with a hydraulic conductivity not to exceed 1 x 10-7 centimeters per second overlain with at least a sixty mil flexible membrane liner), and at least one-foot of non-TENORM waste or daily cover material by the end of each operating day (or once every 24-hour period for continuous operations). TENORM waste must be buried at least 10 feet below the surface of the final cover. Additional cover thickness may be required depending on the slope of the landfill. The leachate collection system and groundwater monitoring network shall be analyzed for background concentration of radionuclide parameters prior to receipt of any TENORM waste. Leachate shall be analyzed for radionuclides at the same frequency as groundwater samples are collected. If radionuclides are detected in leachate at a concentration greater than the concentrations listed below, then the groundwater monitoring network must begin analysis for radionuclide parameters: - Radon: 4,000 picocuries per liter (pCi/L) - Combined Radium-226 and Radium-228: 5 pCi/L - Alpha particle activity (excluding radon and uranium): 15 pCi/L - Uranium: 30 micrograms per liter (ug/L). C.6. Colorado According to data from the U.S. Energy Information Agency, in 2016, Colorado accounted for 5.1% of the U.S. oil and gas production from conventional and unconventional resources. Oil and gas wastes in Colorado is regulated by the Oil and Gas Conservation Commission under the Department of Natural Resources. Off-site waste disposal and TENORM are regulated by the Colorado Department of Public Health and Environment. Numerous sections of the Colorado oil and gas regulations were revised in Management of Exploration, Development and Production Wastes Appendix C: State Programs C-16 2015 to address practices in unconventional resource exploration and production. Additional updates were made in 2016. Table C-6 provides a summary of the regulations identified for E&P wastes in Colorado. Table C-6. Summary of Regulations for E&P Wastes in Colorado Topic Area Definitions Waste Unit Location Requirements Summary Section 100 of the Colorado Oil and Gas Code provides over 180 definitions including definitions for 15 pit types: drilling pits (includes ancillary pits, completion pits, flowback pits, and reserve pits), production pits (includes skimming/settling pits, produced water pits, percolation pits and evaporation pits) special purpose pits (includes blowdown, flare, emergency, basic sediment/tank bottom, workover and plugging pits) and reserve pits. The definition of exploration and production waste cites the RCRA exemption and provides additional clarification that wastes derived from gas plants along feeder lines, regardless of change in gas custody, are included in the definition. The regulations define a designated setback zone which incorporates definitions for two different setback zones (exclusion and buffer), and urban mitigation areas where additional regulations may apply. Colorado setback requirements for well and production facilities vary depending on activity and structure types. For example, the setback is 350 feet for designated outside activity areas and 1,000 feet for high occupancy building units. These requirements may be less restrictive with a mitigation plan. Production pits, special purpose pits (other than emergency pits), and flowback pits containing E&P waste shall not be allowed within a defined Floodplain, unless approved by the director. In addition, the operator must determine whether the proposed oil and gas location falls within Sensitive Wildlife Habitat or a Restricted Surface Occupancy area (definitions provided in regulations). A consultation with Colorado Parks and Wildlife is then required. Minimum depth to groundwater for pits is not specified. Tank construction and operation regulations provide general requirements. For example, buried or partially buried tanks, vessels, or structures used for storage of E&P waste shall be properly designed, constructed, installed, and operated in a manner to contain materials safely. A synthetic or engineered liner shall be placed directly beneath. Such vessels shall be tested for leaks after installation and maintained, repaired, or replaced to prevent spills or releases of waste. There are special requirements for setback locations. Tank Requirements Tank berms and containment structures must be sufficiently impervious and are required for all tanks containing oil, condensate, or produced water with greater than 3,500 milligrams per liter (mg/l) total dissolved solids (TDS). Recent regulations specify that containment berms around all tanks must be constructed of steel rings or another engineered technology. Requirements are not provided for modular large volume tanks or netting of open tanks. Tank bottoms may be addressed by disposal at a commercial solid waste disposal facility, treatment at a centralized E&P waste management facility, injection into a permitted Class II injection well, or by an alternate method approved by the director. Pit Construction and Operation Requirements Permits are required for pits covered by these regulations: drilling pits, ancillary pits, completion pits, flowback pits, reserve pits, production pits, skimming/settling pits, produced water pits, percolation pits and evaporation pits. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-17 Table C-6. Summary of Regulations for E&P Wastes in Colorado Topic Area Summary Pits are not allowed within the Buffer Zone Setback (1,000 feet), except fresh water storage pits, reserve pits to drill surface casing, and emergency pits. In addition, unlined pits cannot be constructed on fill material or in areas where pathways for communication with ground water or surface water are likely to exist. Liners are required for certain pit types or waste characteristics (details are provided in the regulations). In Sensitive Areas, the director may require a leak detection system for the pit or other equivalent protective measures, that may include increased recordkeeping requirements, monitoring systems, and underlying gravel fill sumps and lateral systems. In making such determination, the director shall consider the surface and subsurface geology, the use and quality of potentially-affected ground water, the quality of the produced water, the hydraulic conductivity of the surrounding soils, the depth to ground water, the distance to surface water and water wells, and the type of liner. In addition, pit level indicators shall be used within Designated Setback Locations. Pit Construction and Operation Requirements (Cont.) Pits must be constructed, monitored, and operated to provide for a minimum of two (2) feet of freeboard at all times. Netting and fencing requirements appear to be a site specific decision by the operator (and approved by the director), as follows: appropriate netting or fencing shall be used where necessary to protect public health, safety and welfare or to prevent significant adverse environmental impacts resulting from access to a pit by wildlife, migratory birds, domestic animals, or members of the general public.” Well sites constructed within Designated Setback Locations must be adequately fenced to restrict access by unauthorized persons. Baseline groundwater sampling is required for new wells (not specific waste units), and signage is required for wells, batteries, centralized E&P waste management facilities and tanks, but neither is indicated for tanks specifically. Discharge permits are required for produced water discharging into Colorado state waters. Produced water, emergency and flare pits are identified as temporary, but requirements are not provided. Non-commercial fluid recycling pits are addressed as multi-well pits. Permitted centralized pits are allowed for the treatment, disposal, recycling or beneficial reuse of E&P waste. This rule applies only to non-commercial facilities. Centralized facilities may include components such as land treatment or land application sites, pits, and recycling equipment. Requirements are not specified for minimum depth to groundwater, berm construction, run-on and run-off controls, or inspections. Pit Closure Requirements Removal of liquids and solids is required prior to pit closure. While a specific schedule is not provided for pits, general reclamation for wells is within 3 months on crop land and 12 months on non-crop land. Inspection is required for general site reclamation (not pits specifically). Sampling is necessary to ensure that remaining soil and groundwater concentrations meet specified values (found in Table 910-1). Financial security for pits is not required separately but is included as a part of the overall well permit bond. Spill Notification Notification of spills is required within 24 hours if certain criteria are met. Corrective Action A Site Investigation and Remediation Workplan (Form 27) may be required when threatened or actual significant adverse environmental impacts on any air, water, soil or other environmental resource from a spill/release exist or when necessary to ensure compliance with the concentration levels in Table 910-1 with consideration to Colorado Water Quality Control Commission (WQCC) ground water standards and classifications. Such spills/releases shall be remediated in accordance with oil and gas regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-18 Table C-6. Summary of Regulations for E&P Wastes in Colorado Topic Area Off-site Landfills Summary Waste disposal at off-site facilities is allowed for produced water (permitted commercial facilities) and drilling fluids and oily waste (commercial solid waste facilities). Other waste such as workover fluids, tank bottoms, pigging wastes from gathering and flow lines, and natural gas gathering, processing, and storage wastes may be addressed by disposal at a commercial solid waste disposal facility, treatment at a centralized E&P waste management facility, injection into a permitted Class II injection well, or by an alternate method approved by the director. Land application of some E&P waste is allowed in Colorado. Water/bentonite-based muds do not require a permit and may be used for lease road and site construction (other uses require approval), or land treatment/application at a centralized E&P waste management facility. Land Application Water-based bentonitic drilling fluids may be applied at a centralized E&P waste management facility at an average thickness of no more than three (3) inches prior to incorporation. The drilling fluids must be applied to prevent ponding or erosion and incorporated as a beneficial amendment into the native soils within ten (10) days of application and resulting concentrations shall not exceed those in Table 910-1. Director approval is not required when such drilling fluids are used a soil amendment. Oily waste includes those materials containing crude oil, condensate or other E&P waste, such as soil, frac sand, drilling fluids, and pit sludge that contain hydrocarbons. Land treatment of oily waste is allowed onsite or at centralized E&P waste management permitted facilities. Requirements include removal of free oil from the oily waste prior to land treatment, no pooling, ponding, or runoff, and no contamination of storm water runoff, ground water, or surface water. Treatment by disking, tilling, aerating, or addition of nutrients, microbes, water or other amendments, is required to enhance biodegradation. Land-treated oily waste incorporated in place or beneficially reused must be in compliance with the concentrations in Table 910-1. Beneficial use of E&P waste in Colorado includes spreading produced water (with less than 3,500 mg/L TDS) on lease roads outside sensitive areas, when authorized by the surface owner and in accordance with an approved waste management plan (per Rule 907.a(3)). Such road spreading shall not impact waters of the state, shall not result in pooling or runoff, and the adjacent soils shall meet the concentration levels in Table 9101. Use of flowback fluids is not allowed for dust suppression. Beneficial Use Waste Minimization/ Management In addition, to encourage and promote waste minimization, operators may propose plans for managing E&P waste through beneficial use, reuse, and recycling by submitting a written management plan to the director for approval on a Sundry Notice. Such plans shall describe, at a minimum, the type(s) of waste, the proposed use of the waste, method of waste treatment, product quality assurance, and shall include a copy of any certification or authorization that may be required by other laws and regulations. The director may require additional information. Closed loop drilling systems are required within the Buffer Zone Setback. Waste minimization is considered a best management practice and encouraged, as noted above. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-19 Table C-6. Summary of Regulations for E&P Wastes in Colorado Topic Area Summary Produced water may be disposed at permitted commercial facilities. Commercial Recycling and Reclamation Facilities No person shall accept water produced from oil and gas operations, or other oil field waste for disposal in a commercial disposal facility, without first obtaining a Certificate of Designation from the County in which such facility is located, in accordance with the regulations pertaining to solid waste disposal sites and facilities as promulgated by the Colorado Department of Public Health and Environment. Financial security, offsite manifests and monitoring/testing during commercial recycling operation are not specifically addressed in these regulations. NORM and TENORM C.7. The Colorado Department of Public Health and Environment has authority under numerous Colorado statutes and regulations that are relevant to the control and disposition of TENORM. Interim Policy and Guidance issued in 2007 clearly describes disposal options and locations for oil and gas-related TENORM. Testing is required for each shipment prior to transport. TENORM disposal is allowed, and limitations vary with the type of facility. One hazardous waste landfill in Colorado can accept up to 400 pCi/g Ra-226 and 2,000 pCi/g total activity, with a constraint on source material limits for uranium and thorium. Three similar facilities exist in other states. Municipal solid waste landfill limitations include 3 pCi radon, 30 pCi uranium, and 3 pCi thorium. Action/Management Plans and storage requirements are not specifically addressed in the interim policy. Wyoming In 2016, Wyoming accounted for approximately 4.9% of the nation’s oil and gas production according to the U.S. Energy Information Agency. E&P wastes generated in Wyoming are regulated by the Wyoming Oil and Gas Conservation Commission. Regulations regarding wastes disposed offsite are not specifically addressed in the regulations. NORM and TENORM wastes are regulated under the Wyoming Department of Environmental Quality Solid and Hazardous Waste Division. Several areas of the regulations, including new groundwater monitoring requirements, were updated in 2015 and 2016. Table C-7 provides a summary of the regulations identified for E&P wastes in Wyoming. Table C-7. Summary of Regulations for E&P Wastes in Wyoming Topic Area Summary The following pits are subject to this regulation: (i) Reserve pits on the drilling location; (ii) Reserve pits off the location within a lease, unit or communitized area permitted by Owner or unit Operator drilling the well; Definitions (iii) Produced water retention pits, skim pits, and emergency production pits including the following: (A) Pits associated with approved disposal wells which act as fluid storage, filtering or settling ponds prior to underground disposal in a Class II well; (B) Pits constructed for disposal of produced fluids in connection with oil and gas exploration and production used as part of the filtering and/or settling process upstream of a National Pollutant Discharge Elimination System (NPDES) discharge point; Management of Exploration, Development and Production Wastes Appendix C: State Programs C-20 Table C-7. Summary of Regulations for E&P Wastes in Wyoming Topic Area Summary (C) Pits constructed in association with heater treaters or other dehydration equipment used in production, such as free water knockouts, or first, second and third stage separators; Definitions (cont.) (D) Pits constructed for blowdown or gas flaring purposes. (iv) Pits constructed for the storage and treatment of heavy sludges, oils, or basic sediment and water (BS&W) in connection with production operations; (v) Temporary pits constructed during well workovers, including spent acid and frac fluid pits; (vi) Permanent or temporary emergency use pits; (vii) Miscellaneous pits associated with oil and gas production not listed above. Waste Unit Location Requirements Wyoming residential setback requirements for wells and production facilities address occupied structures (residential, school, business, and hospital use). Pits are prohibited “in drainages, or in the floodplain of a flowing or intermittent stream, or in an area where there is standing water during any portion of the year” and unlined pits are prohibited in fill material. Critical areas for pit placement are also defined and include criteria for distances to water supplies and wetlands, residences and other structures, groundwater depth, total dissolved solids content and soil type. While pits are not prohibited in critical areas, they may require additional protection. In addition, the Wyoming Environmental Quality Act restricts any commercial oil field waste disposal facility from being constructed or operated within one mile of any occupied dwelling or any public or private school, without approval. Endangered species are not specifically addressed in the regulations; however the regulations do indicate the Commission shall adopt policies and practices that may be required in compliance with the Greater Sage-Grouse Core Protection Area. Tank Requirements Rules include general performance requirements of tanks (“maintain tanks in a work-like manner which will preclude seepage from their confines and provide for all applicable safety measures”). The use of crude oil tanks without tops is strictly prohibited. There are no specific requirements in the oil and gas regulations for berm and containment materials for tanks, or for protective netting and tank monitoring. However, “If an SPCC Plan is applicable, any oil spilled within the SPCC containment berms at a tank battery shall be promptly removed and any containment devices installed to contain drips and spills during hose hookup shall be emptied and/or cleaned as necessary to prevent access by wildlife, domestic animals, or migratory birds.” A permit is not required for tank bottom removal, but disposal of produced water, tank bottoms and other miscellaneous solid waste should be in a manner which is in compliance with the Commission’s rules or other state, federal, or local regulations. Modular large volume tanks are not specifically addressed in the regulations. Pit Construction and Operation Requirements WOGCC rules cover construction and operation of various pit types, including reserve pits, produced water pits, skim pits, emergency pits, temporary pits and miscellaneous pits. Emergency pits are defined as temporary pits. Pits in critical areas with groundwater less than 20 feet are prohibited, and unlined pits shall not be constructed in fill. Reserve pits cannot be used as production pits; hazardous waste pits are prohibited. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-21 Table C-7. Summary of Regulations for E&P Wastes in Wyoming Topic Area Summary Liners are required for pits constructed in fill or those retaining oil base drilling muds, high density brines, and/or completion or treating fluids, or if the produced water has a total dissolved solids concentration greater than 10,000 mg/L. Details for liners and slopes (3:1) are provided, while general guidelines are included for freeboard (Liquids must be kept at a level that takes into account extreme precipitation events and prevents overtopping and unpermitted discharges.) Specifications for other elements of pit construction and operation including run-on/run-off controls and berm construction are not included in these rules. Fencing is required for all pits and netting is necessary when timely removal of fluid is not possible. Signage is required for each pit, unless in close proximity to marked wells. Pit Construction and Operation Requirements (Cont.) Discharge permits are required to discharge stormwater that has come in contact with any overburden, raw material, intermediate products, finished products, byproducts or waste products located on the site. Storm water discharges associated with small construction activity require permit authorization as of March 10, 2005. A groundwater baseline sampling, analysis and monitoring plan for the site (not specific to pits) is required as part of the application to drill or deepen a well. “Monitoring systems may be required for pits constructed in sensitive areas [as specified in the permit]. Such pits must be operated in a manner that avoids damage to liner integrity. Periodic inspections, weekly at a minimum, of pits must be made by the Owner or Operator and documentation of such inspections may be required to be submitted to the Supervisor at his request… The Supervisor is also authorized to require the testing necessary for the regulation of oil field pits and wastes.” Permits for noncommercial centralized pits may be more stringent than for individual pits; they are issued for a five-year term and may be renewed at the discretion of the Supervisor. Noncommercial fluid recycling pits are not specifically addressed in these regulations. Pit closure may include evaporation and subsequent burial of solids depending on the fluids, type of pit and solids content. Burial methods cannot compromise the integrity of the liner without written approval by the Supervisor. One-time landspreading of reserve pit fluids on the drilling pad may be approved. Trenching or squeezing of pits is expressly prohibited. Notice (24 hours) is required prior to pit closure to allow the Commission staff to witness closure operations. Commercial treatment of pits may be approved. Pit Closure Requirements Pit reclamation should be completed in a timely manner as climatic conditions allow. Production and reserve pits should be reclaimed after they have dried sufficiently following removal of any oil, sheens or other hydrocarbons, and no later than one year after the date of last use, unless a variance is granted. High salt content materials must be removed prior to pit closure. Inspections may be required (at the Commission’s option), and sampling is determined by the Supervisor based upon site-specific conditions. All disturbed areas on state lands will be reseeded. A Sundry Notice shall be submitted upon completion of pit closure. Pit bonds may be required. Pits used solely for the retention of water produced in association with the recovery of coalbed methane gas in the Powder River Basin may be left open with approval. Spill Notification Oil and gas rules indicate that uncontained spills or unauthorized releases of produced fluids, drilling muds, produced water, hydrocarbons, or chemicals which enter, or threaten to enter, waters of the state must be verbally reported to the Commission no later than the next business day following discovery of the incident. The Owner or Operator shall file a written report within 15 working days. Notification for contained spills depends upon the volume of the spill. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-22 Table C-7. Summary of Regulations for E&P Wastes in Wyoming Topic Area Summary Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills Regulations for offsite disposal are unclear. Testing of the waste is determined by the Supervisor based upon site-specific conditions. Regulations do not address drill cuttings as daily cover in landfill. Land Application Beneficial Use Regulations related to land application and beneficial use are intertwined in the regulations and may be somewhat confusing. Landfarming and landspreading must be approved by the Department of Environmental Quality, whereas jurisdiction over roadspreading or road application is shared by DEQ and the Commission. The Commission is the agency responsible for permitting road applications of E&P wastes in drilling fluids, produced water and produced water-contaminated soils, waste crude oil, sludges, and oil-contaminated soils inside the boundaries of a lease, unit, or communitized area. Landfarming, landspreading, and roadspreading shall be protective of human health and the environment and shall be performed in compliance with all other applicable State and Federal regulations and requirements.” Testing and analysis are required on permit applications for road application of wastes. Depending upon location of pit, the Commission may make modifications as necessary to provide additional protection from site activities, which may include running a closed drilling system. In areas where groundwater is less than 20 feet below the surface, a closed system must be utilized for well drilling operations. Waste Minimization/ Management Commercial Recycling and Reclamation Facilities NORM and TENORM “The Commission encourages the recycling of drilling fluids and by administrative action approves the transfer of drilling fluids intended for recycling. When removed as a product for use in a drilling operation on another lease, drilling fluid is not classified as a waste. If federal leases are involved, the Owner or Operator must obtain the approval of the Bureau of Land Management (BLM). The Supervisor requires the following information be included on the Form 14B or on a Sundry Notice (Form 4) estimated volume, estimated date of transfer, mud recap, analyses which include at a minimum, pH, chlorides, and oil and grease. To protect shallow groundwater, drilling muds with chlorides testing in excess of 3,000 parts per million or those containing hydrocarbons cannot be used in drilling operations until after the surface casing has been set.” Regulations do not address commercial recycling or reclamation facilities. The Wyoming Department of Environmental Quality, Solid and Hazardous Waste Division (SHWD) provides guidelines regarding NORM, which is considered a solid waste, and states the regulation of NORM is supported by existing statutes and regulations. Solid waste disposal is allowed up to 50 pCi/g of radium-226 but the volume accepted depends on the concentration. Up to 20 cubic yards of waste containing NORM between background (or 8pCi/g) and 30 pCi/g of radium-226 may be disposed in a statepermitted solid waste disposal facility with approval from the landfill operator, and may be stored for up to one year without prior written authorization from SHWD. Up to 10 cubic yards with NORM between 30 and 50 pCi/g may be disposed in a state-permitted solid waste disposal facility with approval from the landfill operator and a minimum 4feet of approved cover material. Such waste may be stored for a period not to exceed 180 days without prior written authorization from SHWD. NORM/TENORM wastes exceeding 50 pCi/g of radium-226 cannot be disposed in conventional solid waste facilities in Wyoming and must be disposed at facilities outside of Wyoming that accept such low-level radioactive waste. Oil and gas regulations do not address NORM/TENORM. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-23 C.8. New Mexico In 2016, New Mexico accounted for approximately 4.6% of the nation’s oil and gas production according to the U.S. Energy Information Agency. Oil and gas are produced from both conventional and unconventional resources, and the state also has coal bed methane production. The New Mexico Oil Conservation Division (OCD) within the Department of Energy, Minerals and Natural Resources regulates oil and natural gas production. The Environmental Improvement Board is responsible for the promulgation of rules and standards in many areas including food protection, air, radiation, waste, drinking water and others. NORM related to oil and natural gas production is regulated by both the New Mexico Oil Conservation Division and the Environmental Improvement Board. OCD has promulgated a set of 15 rules (chapters) which include extensive requirements for waste management. Title 19, Chapter 15, Part 17 (Pits, Closed-Loop Systems, Below-Grade Tanks and Sumps) was updated in June 2013. Most sections in Part 2 (General Provisions for Oil and Gas Operations) were updated in December 2008 but a few were amended several times since then including the latest in June 2018. The waste management practices (produced water, drilling fluids, liquid wastes, and surface waste management facilities were updated in 2015 and 2016. Table C-8 provides a summary of the regulations identified for E&P wastes in New Mexico. Table C-8. Summary of Regulations for E&P Wastes in New Mexico Topic Area Summary Definitions Approximately 180 definitions are provided in the general provisions for oil and gas operations (Title 19, Chapter 15, Part 2). Twenty additional definitions are provided in Part 17 (Pits, Closed-Loop Systems, Below-Grade Tanks and Sumps), which include four types of pits: emergency pit, multi-well fluid management pit, permanent pit and temporary pit. Additional definitions are included in other sections of the regulations. The definitions of pits are comprehensive and sometimes include regulations on their use. For example, the definition of multi-well fluid management pit notes that it can not be used for disposal of drilling, completion or other waste, and any additional of wells for the pit use must go to a hearing. Waste Unit Location Requirements Detailed siting requirements are provided for temporary pits (containing low chloride fluids or not low chloride fluids), permanent pit or multi-well fluid management pits, material excavated during pit construction and below-grade tanks. For example, setbacks for various pits range from 300 to 1,000 feet from residential buildings and 100 to 500 feet from a wetland. Minimum depth to groundwater ranges from 25 to 50 feet below the bottom of the pit/tank depending on the type. Emergency pits are exempt from such location restrictions. Siting requirements are comprehensive and include criteria such as streams, playas, sinkholes, unstable areas, municipal boundaries (not allowed within municipal boundaries), wells, wetlands, mines, and floodplains. Endangered species are not specifically addressed in the siting and location requirements. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-24 Table C-8. Summary of Regulations for E&P Wastes in New Mexico Topic Area Tank Requirements Summary Tank requirements for below-grade tanks are included in the pit requirements and be “constructed of materials resistant to the below-grade tank’s particular contents and resistant to damage from sunlight.” Above ground open-top tanks require screen, nets or be otherwise rendered non-hazardous to wildlife, including migratory birds. Where netting or screening is not feasible, the operator shall on a monthly basis inspect for, and within 30 days of discovery, report discovery of dead migratory birds or other wildlife to the appropriate wildlife agency and to the appropriate division district office in order to facilitate assessment and implementation of measures to prevent incidents from reoccurring. Berms (fire walls) are not required unless tanks are within the city limit or 1000 feet from a residence. Oil and gas regulations include limited requirements for construction or operation of above ground tanks, but the Petroleum Storage Tank division regulates crude oil tanks and has extensive regulations for construction and operation. Modular large volume tanks, tank monitoring and tank bottom removal are not specifically addressed in the oil and gas regulations. Extensive construction and operation requirements are provided for temporary pits, permanent pits and multi-well pits. Permits are required for such pits, and unlined pits are prohibited. The application requirements for pit permits differs for each type of pit and require information on the design, operating, maintenance and closure. Permanent pit design must be signed by a registered engineer. Liner requirements vary by pit type and range from single geomembrane liner (temporary) to primary and secondary liners with a leak detection system (permanent and multi-well). Additional construction details including pit slope, liner installation and performance criteria are provided in the regulations. Signs, fencing and netting are required. A separate pit sign is only required if the pit is not associated with a well site where a sign is already posted. OCD must be given the opportunity to inspect the pit prior to liner installation. Pit Construction and Operation Requirements Minimum depth to groundwater ranges from 25 to 50 feet depending on pit type. A freeboard of 3 feet is required for permanent pits, and the volume of a temporary pit can not exceed 10-acre feet including freeboard. Specifications for berms, ditches and other diversions are not provided but should be constructed to prevent run-on of surface water. The pit application package requires a hydrologic analysis of the proposed pit location and detailed design and operation information. An approved discharge plan is required for some discharges, and a permit is required for the discharge of hydrostatic test water. Groundwater monitoring of the pit or well site is not required but inspections are mandated and operators must inspect pits on daily or weekly basis, depending on pit use, as specified in the regulations. Noncommercial fluid recycling pits are specifically addressed in the regulations and have an extensive set of design requirements and operational requirements. No permit is required for recycling facilities if the water is used for drilling, completion, producing, secondary recovery, pressure maintenance or plugging of wells. Evaporation, storage, treatment and skimmer ponds are addressed in a separate set of regulations and include detailed technical requirements for design and operation. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-25 Table C-8. Summary of Regulations for E&P Wastes in New Mexico Topic Area Pit Closure Requirements Summary Pit closure requirements are well defined in the OCD regulations. A closure plan describing the closure method and procedures is required for all pit types as part of the pit permit application process. Requirements for pit closure are provided based on the final disposal location of the waste (off-site disposal or buried in place). Liquids removal is required prior to pit closure, and solids removal is necessary for off-site disposal. Burial in place is allowed but testing of waste and oils is required. Waste stabilization and a covering by a liner may be required. A closure schedule and sampling requirements (number of samples, analytes and methods) are included in the regulations. Financial security is required for the general well permit, not pits specifically. Inspections of pit closure are not required, but the OCD must be notified prior to pit closure. Release notification is discussed “To require persons who operate or control the release or the location of the release to report the unauthorized release of oil, gases, produced water, condensate or oil field waste including regulated NORM, or other oil field related chemicals, contaminants or mixtures of those chemicals or contaminants that occur during drilling, producing, storing, disposing, injecting, transporting, servicing or processing and to establish reporting procedures.” Spill Notification Notification for a major release includes immediate verbal notification (within 24 hours) and follow-up written notification within 15 days; minor release requires only written notification (within 15 days). A major release includes (1) an unauthorized release of a volume, excluding gases, in excess of 25 barrels; (2) an unauthorized release of a volume that: (a) results in a fire; (b) will reach a watercourse; (c) may with reasonable probability endanger public health; or (d) results in substantial damage to property or the environment; (3) an unauthorized release of gases in excess of 500 MCF; or (4) a release of a volume that may with reasonable probability be detrimental to water or exceed the standards in Subsections A and B or C of 19.15.30.9 NMAC. Minor release means an unauthorized release of a volume, greater than five barrels but not more than 25 barrels; or greater than 50 MCF but less than 500 MCF of gases. Corrective action is specified as “The responsible person shall complete divisionapproved corrective action for releases that endanger public health or the environment. The responsible person shall address releases in accordance with a remediation plan submitted to and approved by the division or with an abatement plan submitted in accordance with 19.15.30 NMAC.” Corrective Action Title 19, Chapter 15, Part 30 (Remediation) has the following objective: “To abate pollution of subsurface water so that ground water of the state that has a background concentration of 10,000 mg/l or less TDS is either remediated or protected for use as domestic, industrial and agricultural water supply, and to remediate or protect those segments of surface waters that are gaining because of subsurface-water inflow for uses designated in the water quality standards for interstate and intrastate surface waters in New Mexico, 20.6.4 NMAC; and abate surface-water pollution so that surface waters of the state are remediated or protected for designated or attainable uses as defined in the water quality standards for interstate and intrastate surface waters in New Mexico, 20.6.4 NMAC.” Management of Exploration, Development and Production Wastes Appendix C: State Programs C-26 Table C-8. Summary of Regulations for E&P Wastes in New Mexico Topic Area Off-site Landfills Summary Disposal of E&P waste is allowed at commercial and non-commercial (operator owned) solid waste facilities as specified in the regulations. Regulations contain an extensive set of requirements for construction, operation, closure and post closure of surface waste management facilities (centralized facilities, landfills, small landfarms, large landfarms, evaporation ponds, treatment ponds and skimmer ponds. Signs are required for all subsurface facilities (landfills and landfarms) and permits are required for all facilities except small landfarms (less than 2 acres and 2000 cubic yards of waste). Testing is required prior to disposal. In addition, produced water may be processed at “recycling facilities such as skimmer and evaporate ponds. Permitted solid waste facilities require financial security. Solid waste guidance allow use of treated petroleum contaminated waste as an alternative daily cover if it meets soil quality criteria for the facility. Land Application E&P waste consisting of soil and drill cuttings predominately contaminated by petroleum hydrocarbons may be landfarmed. Specifications and conditions for landfarming are included in the regulations (for example, the waste must be sufficiently free of liquid content to pass the paint filter test and background testing is required prior to land application). A land farm permit is required for large landfarms and Form C-137 is required for small landfarm. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling and recycling of produced water are considered best management practices but are not required. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are addressed in these regulations, including monitoring/testing during operation and financial security/closure. An offsite reclamation manifest is not required. NORM and TENORM NORM is defined in the environmental regulations and also addressed in a separate section of the oil and gas regulations. Under the oil and gas regulations, NORM with less than 30 pCi/g Ra 226 or 150 pCi/g of any other radionuclide is exempt from disposal regulation. Disposal limitations and conditions are based on the general permit conditions provided in the regulations, and may be allowed at commercial or centralized surface waste management facilities, plugged and abandoned wells and injection wells. Regulations specifically allow NORM to be disposed at or near the surface at the site of generation. An action plan/management plan is required, and testing is required prior to disposal. Storage requirements for regulated NORM are provided in the regulations. C.9. Louisiana In 2016, Louisiana accounted for approximately 4.4% of the nation’s oil and gas production, according to the U.S. Energy Information Agency. Louisiana has long history of producing oil and gas from conventional reservoirs but has recently increased unconventional production from the Haynesville and Tuscaloosa Marine Shale. Less than 10% of Louisiana’s oil and gas production is from offshore, state-controlled lands. The Department of Natural Resources has three offices that oversee oil and gas resources in Louisiana: The Office of Conservation, the Office of Mineral Resources and the Office of Coastal Management. The Geological Oil and Gas Division within the Office of Conservation regulates Management of Exploration, Development and Production Wastes Appendix C: State Programs C-27 oil and gas production activities. The Louisiana Department of Environmental Quality, Office of Environmental Compliance, Division of Emergency and Radiological Services regulates NORM in the state. Oil and gas regulations included in Title 43 Natural Resources, Part XIX Office of Conservation are current as of March 2017, but the regains did not specify when the sections were last updated. NORM regulations contained in Title 33 Environmental Quality, Part XV Radiation Protection are dated October 2014. A new rule regarding hydraulic fracturing in the Haynesville Shale became effective in 2011.. Table C-9 provides a summary of the regulations identified for E&P wastes in Louisiana. Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Summary Approximately 50 definitions are provided for the storage, treatment and disposal of E&P waste in the Definitions section of Chapters 3 (on-site) and 5 (off-site) of Title 43. In Chapter 3 (on-site), a pit is defined as “for purposes of this Chapter, a natural topographic depression or man-made excavation used to hold produced water or other exploration and production waste, hydrocarbon storage brine, or mining water. The term does not include lined sumps less than 660 gallons or containment dikes, ring levees or firewalls constructed around oil and gas facilities.” A slightly different version is presented in Chapter 5 (off-site) where a pit is defined as “an earthen surface impoundment constructed to retain E&P Waste, often referred to as a pond or lagoon. The term does not include lined sumps less than 660 gallons.” Production Pits are defined as either earthen or lined storage pits for collecting E&P Waste sediment periodically cleaned from tanks and other producing facilities, for storage of produced water or other exploration and production wastes produced from the operation of oil and gas facilities, or used in conjunction with hydrocarbon storage and solution mining operations, and include the following types: Definitions 1. Burn Pits―earthen pits intended for use as a place to temporarily store and periodically burn exploration and production waste (excluding produced water) collected from tanks and facilities. 2. Compressor Station Pits―lined or earthen pits intended for temporary storage or disposal of fresh water condensed from natural gas at a gas pipeline drip or gas compressor station. 3. Natural Gas Processing Plant Pits―lined or earthen pits used for the storage of process waters or stormwater runoff. No produced water may be stored in a natural gas processing plant pit. 4. Produced Water Pits―lined or earthen pit used for storing produced water and other exploration and production wastes, hydrocarbon storage brine, or mining water. 5. Washout Pits―lined earthen pits used to collect wash water generated by the cleaning of vacuum truck tanks and other vessels and equipment only used to transport exploration and production waste. Any materials other than E&P Waste are prohibited from being placed in such pits. 6. Well Test Pits―small earthen pits intended for use to periodically test or clean up a well. 7. Emergency Pits―lined or earthen pits used to periodically collect produced water and other E&P Waste fluids only during emergency incidents, rupture or failure of other facilities. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-28 Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Summary 8. Onshore Terminal Pits―lined or earthen pits located in the coastal area used for storing produced water at terminals that receive crude oil and entrained water by pipeline from offshore oil and gas production facilities. Definitions (Cont.) 9. Salt Dome Cavern Pits―lined or earthen pits located in the coastal area associated with the storage of petroleum products and petroleum in salt dome caverns. Reserve pits are also defined as “temporary earthen pits used to store only those materials used or generated in drilling and workover operations.” Production pits, may not be constructed in certain flood hazard boundary areas unless such pits have levees which have been built at least 1 foot above the 100-year flood level and able to withstand the predicted velocity of the 100-year flood. Location, construction and use of such pits is discouraged. These levee height requirements do not apply to production pits less than 10’x10’x4’ deep, contain only brine and produce less than or equal to one barrel of saltwater per day. On-site burn pits and well test pits shall not be located less than 100 feet from a well location, tank battery, separator, heater-treater, or any and all other equipment that may present a fire hazard. Unlined pits and burial cells shall not be deeper than five feet above the high seasonal water table. Contamination of a groundwater aquifer or a USDW with E&P waste is strictly prohibited. In addition, the injection of E&P Waste into a groundwater aquifer or a USDW is strictly prohibited. Waste Unit Location Requirements Commercial solid waste facilities and transfer stations may not be within 1/4 mile of a public water supply well or within 1,000 feet of a private water supply well for facilities permitted after January 1, 2002. Commercial facilities and transfer stations may not be located in any area: where such area, or any portion thereof, has been designated as wetlands by the U.S. Corps of Engineers during, or prior to, initial facility application review, unless the applicable wetland and DNR Coastal Management Division coastal use permits are obtained. Specifications for flood areas discussed above also apply to these facilities. Commercial facilities and transfer stations may not be within 500 feet of a residential, commercial, or public building, church, school or hospital. Additional setbacks are necessary when the perimeter of Type A land treatment units are within the restricted residential area for storage tank sludges and gas [plant wastes waste types 6 and 12 (depending on concentration of total benzene). [Type A Facility―a commercial E&P Waste disposal facility within the state that utilizes technologies appropriate for the receipt, storage, treatment, or disposal of E&P Waste solids and fluids (liquids) for a fee or other consideration. Type B Facility―a commercial E&P Waste disposal facility within the state that utilizes underground injection technology for the receipt, storage, treatment, and disposal of only saltwater or other E&P Waste fluids (liquids) for a fee or other consideration.] Transfer stations are exempt from the location requirement of 500 feet from a commercial building. Location restrictions for land treatment units are discussed in that section below. Endangered species are not specifically addressed in the oil and gas regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-29 Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Summary Commercial facilities and transfer stations shall be operated in compliance with, but not limited to, the following: 1. The area within the confines of tank retaining walls (levees) shall be kept free of debris, trash, and accumulations of oil or other materials which may constitute a fire hazard. Portable gasoline powered engines and pumps must be supervised at all times of operation and stored at least 50' from tank battery firewalls when not in use. Vent lines must be installed on all E&P Waste storage tanks and must extend outside of tank battery firewalls. 2. The area within the confines of tank retaining walls (levees) must be kept free of accumulations of E&P waste fluids and water. Such fluids shall be properly disposed of by injection into a Class II well or discharged in accordance with the conditions of a discharge permit granted by the appropriate state agency. 3. Tank retaining walls shall be kept free of debris, trash, or overgrowth which would constitute a fire hazard or hamper or prevent adequate inspection. 4. Tank retaining walls (levees) must be constructed of soils which are placed and compacted in such a manner as to produce a barrier to horizontal movement of fluids. The levees must be properly tied into the barrier along the bottom and sides of the levees. All levees must be provided with a means to prevent erosion and other degradation. Tank Requirements “Each permanent oil tank or battery of tanks that are located within the corporate limits of any city, town or village, or where such tanks are closer than 500 feet to any highway or inhabited dwelling or closer than 1000 feet to any school or church, or where such tanks are so located as to be deemed a hazard by the Commissioner of Conservation, must be surrounded by a dike (or firewall) or retaining wall of at least the capacity of such tank or battery of tanks, with the exception of such areas where such dikes (or firewalls) or retaining walls would be impossible such as in water areas. At the discretion of the Commissioner of Conservation, firewalls of 100% capacity can be required where other conditions or circumstances warrant their construction. 1. In water, swamp or marsh areas, where the building of firewalls is impossible or impracticable, in the future, permanent tanks shall be placed on an impervious platform surrounded by a metal gutter to catch all the oil and other wastes which may cause either a fire-hazard or pollution. A sump shall be provided to catch the run-off from the gutters; however, if the operator or company has devised a plan which serves the same purpose, the District Manager may after being presented with the plan, waive the above requirements. 2. Tanks not falling in the above categories (Paragraphs 1 and 2) must be surrounded by a retaining wall, or must be suitably ditched to a collecting sump, each of sufficient capacity to contain the spillage and prevent pollution of the surrounding areas.” Netting, modular large volume tanks, monitoring, construction and tank bottom removal are not specifically addressed in the oil and gas regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-30 Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Summary The following pit types are defined and separate specifications are provided in the regulations for Produced Water, Onshore Terminal, and Washout Pits; Reserve Pits; Burn Pits; Well Test Pits; Emergency Pits; Natural Gas Processing Plant Pits, Compressor Station Pits, and Salt Dome Cavern Pits. Permits are required for injection wells, and signage is required for the well site; neither are required for pits specifically. Production pits (except as noted below) require a liner with a hydraulic conductivity no greater than 1 x 10-7 cm/sec for 3 continuous feet of clay, which may include the following types of liners: natural liner; soil/mixture liner, recompacted clay liner, manufactured liner or a combination liner. An alternate groundwater aquifer and USDW protection system may be approved by the Office of Conservation. Pits constructed with a manufactured liner must have side slopes of 3:1 and the liner at the top of the pit must be buried in a 1' wide and 1' deep trench. Sufficient excess liner material shall be placed in the pit to prevent tearing when filled with E&P waste. Pits that meet the following criteria are not required to have a liner: production pits located within an 'A' zone (FEMA - One-percent-annual-chance flood event) that are less than or equal to 10' x 10' x 4' deep; contain only produced brine; and is utilized for gas wells producing less than 25 mcf per day and less than or equal to one barrel of saltwater per day (bswpd). Pit Construction and Operation Requirements Burn pits, compressor station pits, natural gas processing plant pits, well test pits, salt dome cavern pits are exempt from the liner requirements above. Produced water pits, washout pits and onshore terminal pits located in the coastal area shall comply with the above requirements, unless such pit is subject to an approved Louisiana Water Discharge Permit System permit. For Emergency Pits, groundwater aquifer and USDW protection shall be evaluated on a case-by-case basis. Operators who intend to utilize existing or new emergency pits without liners must demonstrate by written application to the Office of Conservation that groundwater aquifer and USDW contamination will not occur; otherwise, emergency pits shall be lined. Applications to demonstrate unlined pits will not contaminate groundwater aquifers and USDW's shall at a minimum address the following: Emergency Incident Rate, soil properties, Groundwater Aquifer Evaluation, and Produced Water Composition (total dissolved solids and oil and grease). All emergency pits required to be lined must conform to hydraulic conductivity requirements (1 x 10-7 cm/sec for 3 continuous feet of clay). No produced water or any other E&P Waste shall be intentionally placed in any emergency pit not meeting the hydraulic conductivity requirements, except in the case of an emergency incident. In emergency situations, notice must be given to the Office of Conservation within 24 hours after discovery of the incident. Produced water and any other E&P Waste must be removed from the pit within seven days following termination of the emergency situation. Levees or walls are necessary to protect pits from surface water flow and serve as secondary containment. Specific requirements for levees are only provided for flood areas (levees must be constructed at least 1 foot above the 100-year flood elevation) and coastal areas (levees must have an elevation of at least 2 feet above mean high tide). A freeboard of 2 feet is required from the top of the pit/levee. Unlined pits shall not be within 5 feet of the seasonal high groundwater table. Minimum depth to groundwater is not specified for other pit types. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-31 Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Summary Upon a determination by the operator or the Office of Conservation that any pit subject to this rule is likely to contaminate a groundwater aquifer or a USDW, the Office of Conservation shall require the timely submission of a plan for the prevention of such contamination. Such plan may include using an under-built drainage and collection system, monitoring wells, and/or other means that the Office of Conservation may approve to prevent or detect contamination. Any required monitor wells shall be registered with the appropriate state agency. When required, monitoring shall be conducted on a quarterly schedule. A written report summarizing the results of such monitoring shall be submitted to the Office of Conservation within 30 days of the end of each quarter. Pit Construction and Operation Requirements (Cont.) Except for reserve pits, operators must notify the Office of Conservation of the intent to construct new pits at least 10 days prior to start of construction. Notification shall contain all information requested in §305.D or §303.K.4 as appropriate. The Office of Conservation may inspect any proposed pit site prior to or during construction; however, initial use of the completed pit need not be deferred if no inspection is made. A waste management and operations plan (WMOP) is required for commercial facilities and transfer stations and should include "a plan for routine inspection and maintenance of monitoring equipment (e.g., gauges, monitor wells, etc.) to ensure and demonstrate compliance with permit and regulatory requirements." Reserve pits are defined as "temporary earthen pits used to store only those materials used or generated in drilling and workover operations." Emergency pits are also discussed, which are only to be used during emergencies. Leak detection monitoring, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. Discharges into man-made or natural drainage or directly into state waters will be allowed only after the necessary discharge permit has been obtained from the appropriate state and/or federal agencies and in accordance with the conditions of such permit. A Louisiana Water Discharge Permit System (LWDPS) permit may be required. A variety of pit closure techniques are allowed: onsite land treatment, burial, solidification, onsite land development, or other techniques approved by the Office of Conservation. Otherwise, all E&P waste must be manifested and transported offsite to a permitted commercial facility unless temporarily used in hydraulic fracture stimulation operations conducted on the Haynesville Shale Zone. Details are provided for each process but specifications about liquids and solids removal is not included specifically. Pit Closure Requirements A pit being closed by passive closure (not defined in the regulations) does require inspection by a conservation enforcement officer. Inspections do not appear to be necessary for other pit closure activities. However, documentation of testing and closure activities, including onsite disposal of E&P waste, shall be maintained in operator's files for at least three years after completion of closure activities. Upon notification, the Office of Conservation may require the operator to furnish these data for verification of proper closure of any pit. If proper onsite closure has not been accomplished, the operator will be required to bring the site into compliance with applicable requirements. Sampling is required prior to closure of any pit and for all closure and onsite and offsite disposal techniques excluding subsurface injection of reserve pit fluids. O&G waste must be analyzed for the following: pH, total metals (arsenic, barium, cadmium, chromium, lead, mercury, selenium, silver, zinc), oil and grease, soluble salts and cationic distributions, and radioisotopes (for pits located in the coastal area closed after October 20, 1990). Management of Exploration, Development and Production Wastes Appendix C: State Programs C-32 Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Pit Closure Requirements (Cont.) Summary Financial security is required for the well site and associated activities. Financial security shall remain in effect until release thereof is granted by the commissioner pursuant to written request by the operator. Such release shall only be granted after plugging and abandonment and associated site restoration is completed and inspection thereof indicates compliance with applicable regulations or upon transfer of such well to an exempt operator. Plugging and abandonment of a well, associated site restoration, and release of financial security constitutes a rebuttable presumption of proper closure but does not relieve the operator from further claim by the commissioner should it be determined that further remedial action is required. Commercial facilities and transfer stations shall maintain a bond or irrevocable letter of credit on file with the Office of Conservation to provide for adequate closure of the facility. A closure schedule was not provided in the regulations. Spill Notification A waste management and operations plan (WMOP) is required for commercial facilities and transfer stations and should include "a contingency plan for reporting, responding to and cleaning up spills, leaks, and releases of E&P Wastes or treatment byproducts, including provisions for notifying applicable local, state and federal emergency response authorities and for taking operator-initiated emergency response actions." Any spills that occur during the offsite transportation of E&P waste shall be reported by phone to the Office of Conservation, within 24 hours of the spill and the appropriate state and federal agencies. Information regarding spills at the well site are not provided in these regulations. Corrective actions resulting from spills are not specifically addressed in the regulations. Corrective Action If monitoring of a groundwater aquifer or USDW indicates contamination due to a discharge from a pit, the owner or operator shall immediately notify the Office of Conservation. Within 30 days, the operator shall empty the pit of all E&P Waste and submit a remedial plan for prevention of further contamination of any groundwater aquifer or any USDW. Upon approval, the remedial plan shall be implemented by the operator and monthly progress reports, reviewing actions taken under the plan and their results, will be filed with the Office of Conservation until all actions called for in the plan have been satisfactorily completed. Regulations state “At the option of the generator, E&P waste may be treated and/or disposed at Department of Natural Resources (DNR) permitted commercial facilities and transfer stations under the provisions of this Chapter or Department of Environmental Quality (DEQ) permitted facilities as defined by LAC 33:V and VII which are permitted to receive E&P Waste which are subject to relevant DEQ regulations. If received, stored, treated and/or disposed at a DEQ regulated facility, E&P waste would become the sole regulatory responsibility of DEQ upon receipt.” It is unclear which type of DEQ regulated facility accepts E&P waste. Off-site Landfills Waste characterization is required prior to offsite storage, treatment or disposal. At a minimum, E&P Waste should be tested for the following constituents: pH, TPH, EC, TCLP benzene, SAR, ESP and the following metals: As, Ba, Cd, Cr, Cu, Pb, Hg, Mo, Ni, Se, Ag and Zn. E&P waste may be re-used as daily cover at a sanitary landfill if compliance with testing criteria is achieved for moisture content, pH, EC, SAR, ESP, total barium, leachate testing for TPH and chlorides, benzene, metals and NORM. The use of reusable material in a sanitary landfill will require written approval of the Department of Environmental Quality. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-33 Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Summary Land application of E&P waste is permitted both on-site and at off-site commercial facilities. Onsite land treatment allows for pits to be closed by mixing waste with soil from pit levees or wall and adjacent areas, as long as the waste/soil mixture does not exceed a pH of 6-9 and specified criteria for metals. Land treatment in submerged wetland, elevated wetland, and upland areas is permitted if the oil and grease content of the waste/soil mixture after closure is < 1% (dry weight). Additional parameters (EC, SAR and ESP) are provided for elevated freshwater wetland areas where the disposal site is not normally inundated and upland areas. Land Application Land treatment at off-site facilities have additional requirements: they shall be isolated from contact with public, private or livestock water supplies, both surface and underground; soil shall contain a slowly permeable horizon at least 12 inches thick containing enough fine grained material within 3 feet of the surface to classify it as fine grained material (CL, OL, MH, CH, or OH under the Unified Soil Classification System) and the seasonal high water table shall remain at least 36 inches below the soil surface. Land treatment cells and associated surface drainage system surfaces shall at no time have an accumulation of oil of more than 1 inch at any surface location, and land treatment cell levels shall be maintained with at least 2 feet of freeboard at all times.C4 The location restriction for land treatment of E&P wastes is typically 1,000 feet from a residential/public building, church, school or hospital. However, waste types 06 (storage tank sludges) and 12 (gas plant waste solids) have additional limitations depending on their benzene concentrations. For example, waste type 06 with a total benzene concentration greater than 113 mg/kg and waste type 12 less than 3,198 mg/kg total benzene may not be within 2000 feet of such buildings, while waste type 12 with total benzene concentrations greater than 3,198 mg/kg is banned from land treatment. Beneficial Use Roadspreading may be conducted using stabilized E&P waste. Reserve pits may be closed by processing the waste material with Department of Environmental Quality approved stabilizing additives and using the mixture onsite to develop lease roads, drilling and production locations, etc. The following conditions must be met for use of waste from reserve pits: pH range of the mixture: 6-12; electrical conductivity (EC) < 8 mmhos/cm; oil and grease content < 1% by weight; total metals content meeting the criteria (see §313.C.2 for limitations), leachate testing for chloride concentration < 500 mg/L; and NORM concentrations do not exceed applicable DEQ criteria or limits. Beneficial use of brine is not specifically mentioned in the regulations. Subsurface disposal of salt water is required and regulated by LAC 43:XIX.401 et seq. Waste Minimization/ Management Closed waste storage systems are encouraged but not required. Produced water is not required to be recycled but may be re-used in hydraulic fracturing stimulation activities in the Haynesville Shale. “In order to encourage the conservation and recovery of resources in the oilfield industry, the processing of E&P Waste into reusable materials, in addition to or beyond extraction and separation methods which reclaim raw materials such as crude oil, diesel oil, etc., is recognized as a viable alternative to other methods of disposal.” C4) Freeboard is most commonly applied to liquid controls, but it also can apply to solid wastes. In this case the waste in the land treatment cell must not come within two feet of the top of the berm. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-34 Table C-9. Summary of Regulations for E&P Wastes in Louisiana Topic Area Summary Commercial Recycling and Reclamation Facilities Off-site treatment, storage and disposal of E&P wastes at commercial facilities and transfer stations is addressed in the regulations. Such activities require approval from the Commissioner and evidence of financial responsibility. A manifest must accompany each shipment, and each load of waste must be sampled (pH, electrical conductivity, chloride (Cl) content and NORM, as required by applicable DEQ regulations and requirements) and results reported on the manifest. An 8-ounce sample (minimum) of each load must be collected and labeled with the date, operator and manifest number, and each sample shall be retained for a period of 30 days. Louisiana Department of Environmental Quality regulations address NORM waste; oil and gas regulations in the state do not. Definitions in Chapter 14 (Regulation and Licensing of NORM) of Title 33 Environmental Quality, Part XV Radiation Protection, include NORM and TERN (technologically enhanced natural radioactive material). NORM is discussed with regards to E&P waste, while TERN is not mentioned again in the regulations. “A general license is hereby issued to mine, extract, receive, possess, own, use, store, and transfer NORM not exempt in LAC 33:XV.1404 without regard to quantity.” Produced waters from crude oil and natural gas production are considered exempt. NORM waste management plan is required to store NORM waste for up to 365 days and should be submitted to the Office of Environmental Compliance for authorization. Storage requirements indicate containers (1) shall be compatible with the NORM waste being stored, (2) shall always be closed and sealed during storage (except when necessary to add or remove waste), and (3) shall not be opened, handled or stored in a matter that may cause them to rupture or leak. Storage of NORM in tanks is allowed but waste piles are prohibited. Inspections of storage areas shall be conducted at least quarterly. Treatment or disposal of NORM waste shall be in accordance with one of the following: 1. by transfer of the wastes to a land disposal facility licensed by the department, the U.S. Nuclear Regulatory Commission, an agreement state, or a licensing state; NORM and TENORM 2. by alternate methods authorized by the department in writing upon application or upon the department’s initiative. The application for alternative methods of disposal shall be submitted to the department for approval; 3. for nonhazardous oilfield waste containing NORM at concentrations not exceeding 30 picocuries per gram of radium-226 or radium-228 by transfer to a nonhazardous oilfield waste commercial facility regulated by the Department of Natural Resources for treatment if the following are met: a. dilution in the end product after treatment does not exceed 5 picocuries per gram above background of radium-226 or radium-228; b. the nonhazardous oilfield waste commercial facility has a program for screening incoming shipments to ensure that the 30 picocuries per gram limit of radium-226 or radium-228 is not exceeded; and c. the Department of Natural Resources (DNR) approves; or 4. for nonhazardous oilfield waste containing concentrations of NORM in excess of the limits in LAC 33:XV.1404.A.1, but not exceeding 200 picocuries per gram of radium226 or radium-228 and daughter products, by treatment at nonhazardous oilfield waste commercial facilities specifically licensed by the department for such purposes. Regulation of such sites is set forth in a memorandum of understanding between the department and DNR and contained in LAC 33XV.1499 .Appendix C. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-35 C.10. Ohio According to U.S. Energy Information Agency, in 2016 Ohio accounted for approximately 3.4% of the nation’s oil and gas production and includes both conventional and unconventional resources. E&P wastes generated in Ohio are regulated by the Ohio Department of Natural Resources (ODNR), Division of Oil and Gas Resources Management (DOGRM). Wastes disposed offsite fall under the jurisdiction of Ohio Environmental Protection Agency (Ohio EPA) and NORM (cuttings and brine) and TENORM are regulated under both radiation protection and the oil and gas rules. Ohio updated its oil and gas regulations in 2005 to address urban drilling, and again in 2013 for horizontal wells and related waste management issues. Table C-10 provides a summary of the regulations identified for E&P wastes in Ohio. Table C-10. Summary of Regulations for E&P Wastes in Ohio Topic Area Summary Definitions Definitions in the oil and gas regulations cover relatively broad areas (i.e. production operation includes all activities from pad construction to plugging) and do not include definitions for different types of pits. “Urbanized areas” and “horizontal wells” have recently been added to the definitions. Waste Unit Location Requirements Ohio setback requirements for wells and tank batteries address inhabited structures (residential business and other uses), various water resources, and streets. The regulations do not address setbacks related to endangered species or wildlife. Pits are not specifically identified in setback requirements however because they are part of the well pad they are covered by well setback rules. Tank Requirements Tanks can be used to hold any waste or produced materials. Rules include general performance requirements (“must be constructed and maintained to prevent the escape of waste”) but cannot be buried without approval. If approved, buried steel tanks must be steel and catholically protected. There are no specific requirements in the oil and gas regulations for berm and containment materials for tanks, or for protective netting and tank monitoring. Modular large volume tanks are not specifically addressed in the regulations. Pit Construction and Operation Requirements DOGRM rules require a waste management plan as part of the well permit application including a description of the pit construction and use. Thus, the rules tend to be general and details are left to the well-specific permits and waste management plans approved by the agency. Rules cover construction and operation of temporary pits (including drilling, completion and production uses) and appear to allow the director discretion in approving and requiring site specific conditions. As of January 2014, pit permits are required. A general requirement for proper construction and safe operation addresses pit management (pits of sufficient size and shape must be constructed adjacent to each drilling well to contain all the drilling muds, cuttings, salt water and oil; no fluid is allowed to overflow). Pits are not allowed as permanent disposal locations for brine or materials coming in contact with refined oil-based substances or other sources of contaminants. Synthetic pit liners are required, but the operator may request a variance. Fencing (urbanized areas and near inhabited structures only) and signage (for the well, not specifically for the pit) are required but specifications for other elements of pit construction and operation including leak detection/monitoring, netting, inspection, freeboard, run-on/run-off controls and berm construction are not included in the rules. Centralized pits are not specifically addressed in the regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-36 Table C-10. Summary of Regulations for E&P Wastes in Ohio Topic Area Summary Pit Closure Requirements Closure requirements for pits containing fluids from hydraulic fracturing require removal of all materials “upon termination of the fracturing process” and drilling pits in urbanized areas must be closed within thirty days. Inspections and closure sampling are not required by the regulations. Financial security for pits is not required but is included as a part of the overall well permit bond. Spill Notification New rules require owners and operators to report releases of oil, condensate, brine, chemical substances and oilfield waste materials that occur above specified thresholds and outside of appropriate containment into the environment. Corrective Action Corrective action is not specifically addressed in state regulations. Off-site Landfills Drill cuttings that have come into contact with refined oil-based substances or other sources of contamination must be disposed of at a licensed offsite solid waste landfill unless otherwise approved by the Division. Cuttings from air or water-based drilling that have not come into contact with contaminants are not managed as solid waste and may be buried onsite, if in the approved Waste Management Plan. Oil and gas regulations do not require testing of the material for offsite disposal, however disposal facility permits may require testing. Regulations do not address drill cuttings as daily cover in landfill. Land Application Regulations give flexibility to include land application in the site-specific waste management plan, but such requests must be approved by the agency. Beneficial Use Uncontaminated cuttings may be used offsite for beneficial use but must first obtain approval from Ohio EPA’s Division of Materials and Waste Management. Ohio allows county governments to permit the use of brine for road treatment. If the county allows roadspreading certain requirements must be met regarding the distance from vegetation and application methods. Brine from horizontal wells, drilling fluids, and flowback are not allowed to be spread on a road. The brine source must be reported, but fluid testing is not required under the state regulations. Waste Minimization/ Management Best management practice documents for well site construction and pre-drilling water sampling are noted in the regulations. Ohio does not have a best management practices manual for E&P waste, however in 2014 ODNR produced a fact sheet summarizing management practices for cuttings from shale wells. Closed loop drilling is not specifically addressed in the regulations, but tanks are allowed for containing drilling fluids. Commercial Recycling and Reclamation Facilities Commercial E&P waste recycling or reclamation facilities must have a permit to operate as of January 2014. A detailed description of the process including estimated waste volumes is required in the application. NORM and TENORM NORM, including brine and uncontaminated cuttings, are not regulated in Ohio. Drillingrelated waste (e.g. tank bottoms, pipe scale, filtrate, recycled cuttings) that is suspected to be TENORM must be tested for radium-226 and radium-228 before leaving the well site; TENORM cannot be disposed of at an oil and gas drill site. Solid waste landfills can only accept TENORM wastes for disposal at concentrations less than 5 pCi/g above natural background (“natural background” is two picocuries per gram or the actual value measured at the site). C.11. West Virginia In 2016, West Virginia accounted for approximately 3.1% of the nation’s oil and gas production according to the U.S. Energy Information Agency. Most of West Virginia’s production is from Management of Exploration, Development and Production Wastes Appendix C: State Programs C-37 unconventional resources in the Marcellus Shale, however there is a small amount of shallow oil production and coalbed methane production in the state, and deeper intervals have been explored recently. The Department of Environment Protection regulates oil and natural gas production (Office of Oil and Gas) and solid waste (Solid Waste Management Section). The West Virginia Department of Health and Human Resources regulates TENORM related to oil and natural gas production in the state. West Virginia Code Title 35 contains the oil and gas rules. Series 8 is a new oil and gas rule that became effective in 2016 for horizontal wells. It is an amendment to the Department of Environmental Protection, Oil and Gas rules. The new rules require the well application to include a water management plan describing the disposal procedures for fracturing and stimulation wastewater, and construction and operation requirements for unconventional wellsite pits and centralized pits. The section also requires water quality testing of wells and springs within 1,500 feet of the well pad. Title 35 Series 2 (1998) implements the solid waste permit by rule requirements for solid waste facilities at E&P sites. Table C-11 provides a summary of regulations identified for E&P wastes in West Virginia. Table C-11. Summary of Regulations for E&P Wastes in West Virginia Topic Area Definitions Summary Approximately 30 definitions are provided in the different parts of oil and gas regulations, including definitions for pits and impoundments. The definitions do not include many technical terms. Pits are any man-made excavation or diked area that contains or is intended to contain an accumulation of process waste fluids, drill cuttings, and/or any other liquid substance that could impact surface water or groundwater, whereas impoundments are man-made excavations or diked areas for the retention of fresh water and into which no wastes of any kind are placed. Definitions do not further divide pit types. Technical specifications are provided in many parts of the rules, but some regulations provide only general requirements or performance-based criteria. For example, tank construction rules note that tanks for storage of oil or other pollutants must be compatible with the material stored and the conditions of storage; and, saltwater disposal facilities should be inspected often. Waste Unit Location Requirements Tank Requirements Regulations include general requirements for protection of floodplains, groundwater and surface water from wells and production facilities. Endangered species are not specifically addressed in the regulations. Some specifics, however, are provided, such as no oil or gas well shall be drilled nearer than two hundred feet from an existing water well or dwelling without first obtaining the written consent of the owner of such water well or dwelling. Location requirements are also included for centralized pits and impoundments with capacity of more than 5,000 barrels, which specify a minimum depth to groundwater of 20 inches. General tank requirements indicate that berms should be “…sufficiently impervious to contain spilled oil…” For drilling, completion, workover and production operations, secondary containment shall be installed with impermeable basins for tanks used for stored liquids other than freshwater and shall have a capacity of 110% of the largest tank within the battery. Tank monitoring is not required but considered one of several options for spill prevention. Netting for open tanks, modular large volume tanks, construction material and tank bottom removal are not specifically addressed in these regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-38 Table C-11. Summary of Regulations for E&P Wastes in West Virginia Topic Area Summary Regulations refer to pits (with wastewater pits being the only type specified) and centralized pits and impoundments with capacity greater than 5,000 barrels (bbl.). Permits for specific well site work (similar to an Application for Permit to Drill in other states) are required prior to beginning any construction, but pits do not require a special permit. Authorization and approval from the agency is required for centralized impoundments with a capacity of greater than 5,000 bbl. A synthetic liner is required unless an exception is deemed appropriate based on soil analyses. Requirements include fencing, a freeboard of 2 feet, berm specifications, run-on/run-off controls, groundwater monitoring, signage and inspections. Pit Construction and Operation Requirements Additional requirements for centralized pits include geotechnical analysis, water quality testing, leak detection and monitoring and a minimum depth to groundwater of 20 inches. Discharge of produced water from coalbed methane wells is included in the General Water Pollution Control Permit and includes many conditions for water quality limits and testing. Discharges are not allowed from conventional or horizontal wells without a permit. Fencing is required for pits with capacity greater than 5,000 bbl., but regulations do not address netting for pits. West Virginia does not have regulations for noncommercial fluid recycling pits. Pit Closure Requirements Regulations specify liquids removal prior to closure of pits and impoundments and a closure schedule. In addition, inspection and sampling are required. Financial security is included in the well bonding requirement and no special financial security is required for pits or other waste management units. Spill Notification Spill notification is required when a facility discharges (1) more than 1,000 gallons into the water of the state in a reportable discharge or (2) oil or other pollutants into the waters of the state in two reported discharges within any twelve-month period. The oil and gas chief is responsible for reviewing the information and issuing an order to require any corrective action deemed necessary to protect against future spills and forward such recommendations to the Regional Administrator for the EPA. Corrective Action Corrective action is not specifically addressed in state regulations. Disposal of E&P waste is allowed in properly permitted municipal solid waste facilities. A July 2015 WVDEP report on drill cuttings in solid waste facilities identified six solid waste landfills currently accepting drill cuttings (WVDEP, 2015). Collected leachate from these facilities is either processed on-site and discharged to a stream or sent to a Publicly Owned Treatment Works (POTW) facility for processing and Off-site Landfills discharge to a receiving stream. The report also noted that some landfills mix drill cutting materials with municipal solid waste, and others utilize separate dedicated drill cutting material disposal cells. On-site disposal of drill cutting materials is allowed under state regulations, but the 2015 report indicated operators are not utilizing this option. Testing of waste and its use as daily cover are not specifically addressed in the regulations. Land Application Under the General Discharge Permit (GP-WV-1-88) fresh water from centralized or specific well pits may be discharged in accordance with the permit conditions. Prior to discharge the water must be sampled, and it must be sprayed or irrigated so that the vegetation and ground can absorb the discharge without runoff. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-39 Table C-11. Summary of Regulations for E&P Wastes in West Virginia Topic Area Summary Beneficial Use Beneficial use of natural gas well brine is not included in oil and gas regulations but is permitted by the West Virginia Division of Highways for roadway prewetting, anti-icing and de-icing. The approved use is limited to the wintertime application of natural gas well brines in order to minimize the formation of bonded snow and ice to roadway surfaces by utilizing the melting capabilities of salt brine. Specifications and limitations are provided in a memorandum dated 12/22/11. The use of hydraulic fracturing return fluids associated with horizontal or vertical gas wells is not allowable under this memorandum. Waste Minimization/ Management Waste minimization activities, such as closed loop drilling and recycling of produced water, are not required. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. NORM and TENORM TENORM is defined and addressed in state health regulations, not oil and gas regulations. Landfill screening is conducted prior to acceptance of all wastes, and storage requires an annual registration form. TENORM disposal is allowed at a disposal facility with state or NRC registration or as approved by Department of Health and Human Resources. TENORM waste is exempt if less than 5 pCi/g. C.12. California In 2016, California accounted for approximately 2.8% of the nation’s oil and gas production, according to the U.S. Energy Information Agency data. Much of California’s current production is from older, shallow conventional wells, and about 15% is from offshore state lands. High volume hydraulic fracturing is not common in California at this time. E&P waste regulations in California are dispersed among many different agencies making it challenging to develop a comprehensive review of statewide regulatory programs. The California Department of Conservation, Division of Oil, Gas and Geothermal Resources (DOGGR) regulates oil and natural gas production in the state. The California Environmental Protection Agency has several departments, such as the Department of Toxic Substances Control (DTSC), the State Water Resources Control Board (and the associated Regional Water Quality Control Boards [RWQCB]), and California Integrated Waste Management Board, all of which may be involved in the permitting process for oil and gas activities, with DTSC having the primary responsibility for oil and gas solid wastes managed in pits and RWQCB managing discharges from waste units. NORM/TENORM is not specifically addressed in state oil and gas regulations. DOGGR statutes and regulations are current as of February 1, 2019 with various effective dates for each section. Revision dates were not provided in the regulations, but the enacting statutes appear to include several revisions since 2006. Regulations regarding well stimulation treatment (acidizing and hydraulic fracturing) were added in 2015. Solid waste regulations also have varying dates of revision, including many original regulations from 1997. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-40 A Notice of Intention is required to drill for an oil, gas, or geothermal well, and the decision-making body is the State Oil and Gas Supervisor or his or her representative. A consolidated permit incorporating the environmental permits granted by environmental agencies for a project may be issued as a single permit document by the consolidated permit agency. Unlike all the other states, California does not automatically exempt E&P wastes from RCRA subtitle C. DTSC describes the regulatory status of E&P wastes as follows: “In general, E&P wastes that exhibit hazardous waste characteristics are subject to regulation as hazardous waste under the statutory authority of DTSC, except in those cases where the wastes are hazardous solely because they exhibit the federal characteristic of toxicity” (CalEPA, 2002). Table C-12 provides a summary of the regulations identified for E&P wastes in California. Table C-12. Summary of Regulations for E&P Wastes in California Topic Area Summary Approximately 50 definitions are provided in the oil and gas regulations Nearly half of the definitions are included in the Well Stimulation Treatment Regulations section from 2015. Solid waste regulations include over 230 definitions. Definitions “Sump” is defined as “an open pit or excavation serving as a receptacle for collecting and/or storing fluids such as mud, hydrocarbons, or waste waters attendant to oil or gas field drilling or producing operations.” Three types of sumps (pits) are defined: (1) “Drilling Sump” means a sump used in conjunction with well drilling operations. (2) “Evaporation sump” means a sump containing fresh or saline water which can properly be used to store such waters for evaporation. (3) “Operations sump” means a sump used in conjunction with an abandonment or rework operation. Specific setback values are not provided in the oil and gas regulations. Setbacks provided in the solid waste regulations for waste management units include distances from airports, ground rupture and rapid geologic change but not residential areas. Location restrictions for sumps indicate that the “collection of waste water or oil shall not be permitted in natural drainage channels. Contingency catch basins may be permitted, but they shall be evacuated and cleaned after any spill. Unlined evaporation sumps, if they contain harmful waters, shall not be located where they may be in communication with freshwater-bearing aquifers.” Waste Unit Location Requirements Regulations contain a general prohibition on pollution. “Oilfield wastes, including but not limited to oil, water, chemicals, mud, and cement, shall be disposed of in such a manner as not to cause damage to life, health, property, freshwater aquifers or surface waters, or natural resources, or be a menace to public safety.” Disposal sites for oilfield wastes must conform to State Water Resources Control Board and appropriate California Regional Water Quality Control Board regulations. A minimum depth to groundwater is 5 feet for waste management units (including surface impoundments) but not oil and gas sumps specifically. Endangered species are not specifically addressed. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-41 Table C-12. Summary of Regulations for E&P Wastes in California Topic Area Summary Regulations state that secondary containment at production facilities be capable of containing the equivalent volume of the largest single piece of equipment within the secondary containment and confine that liquid for a minimum of 72 hours. Tank Requirements Tank construction requirements at production facilities are not specified but regulations infer tanks are constructed of metal, based on the associated corrosion control requirements. Regulations allow for non-metal tanks, but they are not subject to the testing and construction requirements for steel tanks. Steel tanks must be inspected for corrosion at least once a month and the minimum thickness for a tank shell/wall must be 0.06 inch with a minimum bottom plate thickness ranging from 0.05 to 0.1 inch. Construction requirements include impermeable base and if replaced, it must have a leak detection system that will either: (1) Channel any leak beneath the tank to a location where it can be readily observed from the outside perimeter of the tank, or (2) Accurately detect any tank bottom leak through the use of sensors. The Supervisor may require a tank bottom leak detection system for any tank with a foundation that does not have an impermeable barrier Netting, monitoring and modular large volume tanks are not specifically addressed. As mentioned above, pits are referred to as “sumps” in California. Three sump types are defined in the oil and gas regulations: drilling sump, evaporation sump and operations sump. The permit request form is entitled “Notice of Intention” and is required for the well, not sumps specifically. The following prohibitions were noted in the oil and gas regulations with regards to waste disposal which may apply to sumps (pits): • • Pit Construction and Operation Requirements Open unlined channels and ditches shall not be used to transport waste water which is harmful to underlying freshwater deposits. Oil or water containing oil shall not be transported in open unlined channels or ditches unless provisions are made so that they are not a hazard as determined by the Supervisor. Dumping harmful chemicals where subsequent meteoric waters might wash significant quantities into freshwaters shall be prohibited. Drilling mud shall not be permanently disposed of into open pits. Cement slurry or dry cement shall not be disposed of on the surface. Sumps must be enclosed according to different specifications based upon their location (urban vs. non-urban). Specific details are provided for chain link fences, wire fences and gates. Additional fencing materials may be used if approved by the Supervisor. Sumps, except operations or drilling sumps, which contain oil or a mixture of oil and water shall be screened (netting) to the following specifications: screens should not be greater than 2-inch nominal mesh, be of sufficient strength to restrain entry of wildlife and be supported to prevent contact with the sump fluid. Produced water ponds are regulated by the RWQCB and may be lined or unlined or used as evaporation or percolation pits if approved by the RWQCB. Signage is required for the well site, not pits specifically. Requirements for liners, leak detection monitoring, minimum depth to groundwater, runoff/run-on controls, and groundwater monitoring were not found for sumps but were found for waste management units, but is unclear if these regulations would be applied to onsite E&P waste management operations. The following paragraphs summarize waste management regulations that may apply to pits. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-42 Table C-12. Summary of Regulations for E&P Wastes in California Topic Area Summary Leak detection monitoring is required for waste management units and should be conducted at least every 5 years to determine if “measurably significant” evidence of a release has occurred. Waste management units and their drainage control facilities should be constructed to manage 1000-year with 24-hour precipitation (Class II) or 100-year storm with 24-hour precipitation (Class III). These units should also be designed to withstand the maximum credible earthquake (Class II) or at least the maximum probable earthquake (Class III). Groundwater monitoring is required for waste management units. Pit Construction and Operation Requirements (Cont.) Inspection frequency information was available for production facilities, not sumps or waste management units. Aboveground production facilities shall be inspected at least monthly for leaks and corrosion; facilities not operating properly shall be repaired or replaced. Secondary containment berms shall be inspected monthly, and fluids, including rainwater, shall be removed from secondary containment areas or catch basins. Discharge permits, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. As of January 2015, DOGGR must provide an annual inventory of unlined sumps to the State Water Resources Control Board and the California Regional Water Quality Control boards. Reports for produced water ponds, both lined and unlined, were available online. In January 2019 the requirement for reporting was repealed. Oil and gas regulations state that responsibility for sump closure lies with both RWQCB and DTSC, and DOGGR has responsibility for final site restoration. Under State Water Quality Control Board regulations onsite sumps used for well drilling operations are closed by either removing the wastes for offsite disposal, or removing free liquid and covering the residual wastes, provided that representative sampling of the sump contents show wastes to be nonhazardous. Sampling is required for waste characterization. Drilling mud is classified as a special waste and can be disposed at a special waste landfill. Pit Closure Requirements The lease restoration includes the locations of any existing or previously removed, where known, sumps, tanks, pipelines, and facility settings. Lease restoration includes the removal of all tanks, above-ground pipelines, debris, and other facilities and equipment. Financial security is required for the wells/site, not for pits specifically and a final inspection is required after completion of plugging operations to determine if Division environmental regulations (California Code of Regulations, Title 14, Subchapter 2) have been adhered to. Spill Notification A spill contingency plan is required for each facility. Oil spills shall be promptly reported by phone to the California Emergency Management Agency. Blowouts, fires, serious accidents, and significant gas or water leaks resulting from or associated with an oil or gas drilling or producing operation, or related facility, shall be promptly reported to the appropriate Division district office, but no specific time frame is given. An unauthorized release associated with well stimulation treatment requires a written report to the Division within 5 days and notifying the Regional Water Board and any other appropriate response entities for the location and the type of fluids involved. Corrective Action Corrective action for spills at well stimulation locations include clean up and remediation of the area, and disposal of any cleanup or remediation waste, as required by all applicable federal, state, and local laws and regulations. Regulations indicate that financial assurance is required for spill response and corrective action at production facilities. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-43 Table C-12. Summary of Regulations for E&P Wastes in California Topic Area Off-site Landfills Summary Regulations do not clearly state which type of waste management unit may be used for E&P waste, but Class II or Class III solid waste management units may be allowed. A waste classification system is used to determine waste type. Alternative cover materials may be approved for use as daily cover, but it is unclear if E&P waste is allowed. Land Application Land treatment units (LTUs) are facilities where hazardous materials are applied onto or incorporated into the soil surface so that hazardous constituents are degraded, transformed or immobilized within the treatment zone. LTUs are a waste management option, but it is unclear if E&P waste is allowed. Regulations for LTUs include precipitation and drainage controls, and seismic design criteria. Regulations and requirements for beneficial use of brine (produced water) are not provided in the oil and gas rules, however based on documented practices by RWQCB produced water can be reused for agricultural purposes. The RWQCBs may approve specific requests for beneficial reuse of produced water. In 2016, four oil companies sent oilfield produced water to four irrigation districts near Bakersfield. Beneficial Use https://www.waterboards.ca.gov/publications_forms/publications/factsheets/docs/prod_water_for_ crop_irrigation.pdf Some solid waste is allowed for beneficial use at a solid waste landfill and may include alternative daily cover, alternative intermediate cover, final cover foundation layer, liner operations layer, leachate and landfill gas collection system, construction fill, road base, wet weather operations pads and access roads, and soil amendments for erosion control and landscaping. However, it is unclear if the use of E&P waste is allowed. Beneficial reuse is restricted to those solid wastes appropriate for the specific use and must conform with engineering and industry guidelines, as specified in the planning documents. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in the state regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the state regulations. Regulations addressing NORM/TENORM were not identified. NORM and TENORM However, one facility (Buttonwillow Facility) was identified that accepts radionuclides (in the decay series of U-238, U-235 and Th-232) up to 1,800 pCi/g. This facility serves oil exploration and production companies, among other customers. C.13. Arkansas In 2016, Arkansas accounted for approximately 1.8% of U.S. oil and gas production including conventional and unconventional resources according to the U.S. Energy Information Agency. The Arkansas Oil and Gas Commission regulates oil and gas production, extraction and transportation in the state. The Arkansas Department of Environmental Quality regulates solid and hazardous waste disposal and water quality in the state. NORM is regulated by the Radiation Control Program under the State Board of Health. Regulations were updated in 2009 and 2015 to include unconventional resources in the Fayetteville Shale, Woodford Shale, Moorefield Shale and the Chattanooga Shale. Pit regulations were updated most recently in 2012, and stimulation regulations were updated in 2017. Table C-13 provides a summary of the regulations identified for E&P wastes in Arkansas. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-44 Table C-13. Summary of Regulations for E&P Wastes in Arkansas Topic Area Definitions Waste Unit Location Requirements Tank Requirements Summary Oil and gas regulations include approximately 100 entries and have not been updated since 1991 rule book. Few definitions relate to E&P wastes. The following pits are defined within the text of the oil and gas regulations: circulation pit, completion pit, emergency pit, mud pit, reserve pit, test pit and workover pit. Requirements for floodplains, surface water and groundwater are dispersed in regulations. Prior authorization is required for pit construction in wetlands. Endangered species are not specifically addressed in the regulations. Setback are specified for storage tanks, such as 200 feet from an existing occupied habitable dwelling. If the water table is less than 10 feet below the ground surface, pits shall be constructed above ground or a closed loop system is required. Containment dikes or other structures are required for tanks and shall have the capacity of at least 1.5 times the largest tank the containment structure surrounds. Netting is required for open top tanks to prevent birds and flying mammals from landing in the tank. Modular large volume tanks, construction materials, tank monitoring and tank bottom removal are not specifically addressed in the regulations. Multiple pit types are included in these regulations (circulation pit, completion pit, emergency pit, mud pit, reserve pit, test pit and workover pit) and are covered by a general APD permit. Liners are required and the type depends upon the pit contents. For example, synthetic or compacted clay liners are used for reserve pits; and synthetic, bentonite drilling mud or concrete liners may be used for mud and circulation pits. Pit Construction and Operation Requirements Additional requirements for pit construction include a minimum 2 feet of freeboard and minimum depth to groundwater of 10 feet. A stormwater erosion and sediment control plan (or appropriate guidance document) shall be prepared (or presented) for the well site. Inspections are not required but may be conducted when deemed necessary by the ADEQ staff. Requirements are not provided for leak detection/monitoring, fencing, netting, groundwater monitoring, discharge permits, temporary pits, non-commercial fluid recycling pits or centralized pits. Signs are required for the well and tank batteries but not for pits and other waste management facilities. Pit Closure Requirements Liquids removal is required prior to pit closure. Oily-based solids must be removed, while water-based solids can be buried in place. A schedule for pit closure, based on well type, is provided in the regulations. While inspection is not specified, additional analytical or disposal requirements may be required for oil-based drilling fluids. Financial security for pits is included as part of general APD bond. Spill Notification Spill notification is not specifically addressed in the state regulations. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills E&P waste disposal is allowed at a permitted surface disposal facility, however, oil-based wastes must go to a Class I landfill (municipal). While testing of the waste is not required, RCRA and TSCA waste testing may be required. Use of E&P waste as a daily cover at landfills are not specifically addressed in the regulations. Land Application Disposal of water-based waste by land application is allowed with a permit. Specific limitations/conditions and location restrictions are not included in the regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-45 Table C-13. Summary of Regulations for E&P Wastes in Arkansas Topic Area Summary Beneficial Use Road spreading is an acceptable form of disposal for crude oil bottom sediments and does not appear to be considered beneficial use. Specifications for road spreading are provided in the regulations and indicate that the applied waste shall not have a produced water content greater than 10% free water by volume. Information about beneficial use of brine is not provided in the regulations. Waste Minimization/ Management If oil-based drilling fluids are to be used, and the location of the mud or circulation pit is within 100 feet of a pond, lake, stream, Extraordinary Resource Waters, Ecologically Sensitive Waterbody or Natural and Scenic Waterway, the Operator is required to use a Closed Loop System. As noted previously, if the water table is less than 10 feet below the ground surface, pits shall be constructed above ground or a closed loop system is required. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. NORM and TENORM NORM is regulated by the Radiation Program under the Arkansas State Board of Health. Disposal of NORM is allowed and details about the storage of NORM are provided. Waste is exempt when concentrations are less than 5 picocuries per gram of radium-226 and/or radium-228, 0.05% by weight of uranium or thorium, or 150 picocuries per gram of any other NORM radionuclide, provided that these concentrations are not exceeded at any time. C.14. Utah In 2016, the U.S. Energy Information Agency estimated that Utah accounted for approximately 1.2% of the nation’s oil and gas production. Most of the production is from the northeast part of the state in the Uinta Basin where several different conventional and unconventional resources are targeted. The Division of Oil, Gas and Mining within the Department of Natural Resources regulates oil and natural gas production in the state. Utah Oil and Gas has oversight responsibility for all operations for and related to the production of oil or natural gas, disposal of salt water and oil-field wastes. The Utah Department of Environmental Quality, Waste Management and Radiation Control Division regulates solid and hazardous wastes. NORM/TENORM is not specifically addressed in state oil and gas regulations. The Utah Administrative Code (UAC) Rule 649 contains oil and gas regulations. Several sections of the rule have been updated recently, including Section 3 (Drilling and Operating Practices updated in 2016) which contains most of the permitting, pits, and hydraulic fracturing requirements and Section 9 (updated in 2013) contains the waste management and disposal rules including evaporation facilities, landfarms, and other disposal facilities. Like many states, the waste management regulations specifically exclude pits associated with underground injection wells. Utah Division of Oil, Gas and Mining provide additional resources on ranking criteria to determine waste containment requirements according to sensitivity level to protect the surface and near surface environment. Table C-14 provides a summary of the regulations identified for E&P wastes in Utah. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-46 Table C-14. Summary of Regulations for E&P Wastes in Utah Topic Area Definitions Summary Approximately 80 definitions are provided in the oil and gas regulations (Title R649), including definitions for E&P waste, pit, emergency pit, disposal pit and reserve pit. "E and P Waste" means exploration and production waste and is defined as those wastes resulting from the drilling of and production from oil and gas wells as determined by the EPA, prior to January 1, 1992, to be exempt from Subtitle C of the RCRA. The definition of reserve pit is broader than many other states, and includes pits used for drilling as well as completion and testing. Text in the regulation identifies additional types of pits including workover and completion pits, storage pits, pipeline drip pits, and sumps. UAC Rule 19, solid waste regulations state: "Solid waste does not include… : drilling muds, produced waters, and other wastes associated with the exploration, development, or production of oil, gas, or geothermal energy.” Waste Unit Location Requirements Oil and gas regulations address floodplains, groundwater and surface water but do not include endangered species. Setbacks related to the waste management units (not just the well site) are specified. For example, “Disposal facilities shall be located a minimum of one mile from residences or occupied buildings; not within a floodplain; not within 500 feet of a wetland, water-course or lakebed; and not in permeable soil with groundwater less than 50 feet below the lowest elevation where waste will be placed.” A simple reading of the definition of “disposal facility” indicates that pits used during the drilling and completion may not be considered disposal facilities.C5 The Onsite Pit Guidance states that a pit/trench may not be constructed in fill material or in a drainage or floodplain of flowing or intermittent streams. Depth to groundwater, distances to surface water bodies and water wells, and population within a one-mile radius are factors when determining pit specifications (such as construction materials and liner requirements). Tank Requirements Pit Construction and Operation Requirements C5) General tank requirements indicate that berms should be constructed of sufficient height and width to contain tank contents. Tank monitoring, netting for open tanks, modular large volume tanks, construction material and tank bottom removal are not specifically addressed in these regulations. Specifications and criteria for pit construction are not provided in the regulations, however the text of the regulation states that the pits shall be located and constructed according to the Division guidelines for onsite pits as provided on the Department web page (the Guidance Document), which does provide some specifications and criteria. General regulatory requirements say that pits shall be located and constructed in such a manner as to contain fluids and not cause pollution of waters and soils. Permits for pits are not required but a detailed description of the pit plan appears to be included as part of the APD. The Division conducts a predrill site evaluation to help define reserve pit location and construction requirements (including liner requirements). The Division appears to have significant flexibility and authority to define site specific requirements for pits. "Disposal Facility" means an injection well, pit, treatment facility or combination thereof that receives E and P Wastes for the purpose of disposal [emphasis added]. This includes both commercial and noncommercial facilities. (R 649-1-1 Definitions) Management of Exploration, Development and Production Wastes Appendix C: State Programs C-47 Table C-14. Summary of Regulations for E&P Wastes in Utah Topic Area Pit Construction and Operation Requirements (Cont.) Summary Regulations require fencing and netting (when determined necessary). General requirements for run-on/run-off control and secondary containment are also included. Any intentional discharge of water requires an additional permit from the Division of Water Quality. Freeboard requirements are only specified for evaporation ponds (two feet). Inspections are not required but may be conducted at the discretion of the agency. In addition, leak detection and monitoring may be required in a permit for sensitive areas. Signage is required for the site, not pits specifically. Regulations do not provide specific requirements for temporary and emergency pits, or address noncommercial fluid recycling pits or centralized pits. Pit Closure Requirements Regulations specify liquids and solids removal prior pit closure. Onsite pits must be closed within one year following drilling and completion of the well, and an inspection of the restored well site shall be conducted within 30 days of notification or as soon as weather conditions permit. Sampling of the final pit condition is required, and financial security is part of the well permit bond. Disposal facilities including land farms, composting, bioremediation, solidification and treatment facilities not associated with individual wells (either commercial or noncommercial) require a separate bond. Spill Notification Incident reporting is specified for both major and minor reportable events at oil or gas drilling, producing, transportation, gathering, or processing facility, or at any injection or disposal facility. Major reportable events include an unauthorized release of more than 25 barrels of oil, salt water, oil field chemicals or oil field wastes; and any spill, venting, or fire, regardless of the volume involved that occurs in a sensitive area (parks, recreation sites, wildlife refuges, lakes, reservoirs, streams, urban or suburban areas), and require a verbal notification within 24 hours and a written report within five days. Minor reportable events include unauthorized release of more than 5 barrels and up to 25 barrels of oil, salt water, oil field chemicals or oil field wastes; and require a written report within five days. Corrective Action The regulations include general waste management practices that specify “operators shall catch leaks, drips, contain spills and cleanup promptly.” Additional requirements are not provided. Off-site Landfills Disposal of E&P waste is allowed at both commercial and non-commercial disposal facilities under the oil and gas regulations, but regulations do not specifically address offsite landfills. Utah Solid Waste regulations R315-304 allows E&P wastes to be disposed in Industrial Solid Waste Landfills (Class IIIb). Testing of waste and its use as daily cover are not specifically addressed in either of the regulations groundwater monitoring at Class III landfills is required. Land Application E&P waste may be land applied, and details are provided in the regulations. Specifications indicate waste should be liquid-free and applied to soil with a hydraulic conductivity no greater than 1 x 10-6 cm/sec. Other treatment facilities, such as composting, solidifying, other bioremediation, and water treatment, may be approved. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Based on the numerical risk ranking system for fluid containment describe above, Level I conditions require total containment by closed-loop drilling system, concrete structure or other type of total containment structure or material. Produced water recycling is not required but is recommended. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-48 Table C-14. Summary of Regulations for E&P Wastes in Utah Topic Area Summary Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. NORM and TENORM State oil and gas regulations do not address NORM/TENORM. General radioactive waste regulations address NORM management only and set a disposal limit of 15 pCi/g for Ra 226. C.15. Kansas According to the U.S. Energy Information Agency, Kansas accounted for approximately 1% of U.S. oil and gas production in 2016. Much of the oil and gas is produced from conventional resources but drilling in the unconventional Mississippian Lime Play has increased over the past several years. The Conservation Division of the Kansas Corporation Commission regulates oil and natural gas production in the state. The Kansas Department of Health and Environment, Waste Management Division regulates solid and hazardous waste disposal. NORM/TENORM is not specifically addressed in state oil and gas regulations. Oil and gas regulations, including those related to pits and hydraulic fracturing, were updated in 2009 and 2013, and solid waste regulations applicable to E&P wastes, including landspreading of E&P wastes, were updated in 2013. Table C-15 provides a summary of the regulations identified for E&P wastes in Kansas. Table C-15. Summary of Regulations for E&P Wastes in Kansas Topic Area Summary Definitions Definitions in the oil and gas regulations include over 100 entries. The following pits are covered in the oil and gas regulations: drilling pit (reserve pits and working pits), workover pit, emergency pit, settling pit, burn pit, and haul-off pit. Waste Unit Location Requirements Tank Requirements Overarching regulations for solid waste facilities address siting requirements for floodplains, endangered species, surface water and groundwater. Floodplains and surface water are also addressed in the oil and gas regulations. Exceptions may be requested for siting emergency pits in sensitive groundwater areas. Buffer zones are provided for disposal of drilling waste by land-spreading. For example, land spreading must be at least 500 feet from each habitable structure and at least 100 feet from each intermittent stream. Signage is required for tanks. No other requirements for tanks are provided in these regulations. Permits are required for drilling pits, work-over pits, emergency pits, settling pits, burn pits, and haul-off pits. Burn and confinement pits are defined as temporary. Pit Construction and Operation Requirements Liners are necessary when the Conservation Division requires pits to be sealed; all emergency pits must be sealed. Pit location must be 5 feet above the shallowest water table. Freeboard varies from 12 inches (for drilling, work-over, burn and containment pits) to 30 inches (for emergency and settling pits). Requirements are not provided for leak detection/monitoring, fencing, netting, berm requirements, run-on/run-off controls, groundwater monitoring, non-commercial fluid recycling pits or centralized pits. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-49 Table C-15. Summary of Regulations for E&P Wastes in Kansas Topic Area Pit Closure Requirements Summary Regulations require that pit contents be disposed prior to pit closure. Timeframe for closure depends on the type of pit, which varies from 30 days after cessation for settling, burn and emergency pits to 365 days after the well spud date for drilling pits. Inspection and sampling during pit closure are not specifically addressed in the regulations, but chloride content of the waste is required during permitting. Pit contents can be disposed of in the annular well space, buried in place, or moved to an onsite or offsite disposal location as approved by the director. Financial security for pits is required as part of general APD bond. Spill Notification Spill notification is addressed in the regulations. Corrective Action Corrective action is addressed in the regulations. Off-site Landfills E&P waste disposal is allowed at a sanitary landfill, including a municipal solid waste landfill. Testing of waste and use as a daily cover at landfills are not specifically addressed in the regulations. Disposal of drilling waste by land-spreading requires approval, and conditions for disposal are provided in the regulations. Examples include waste characteristics (10,000 ppm limit for chloride content), as well as site characteristics (maximum slope is 8% and the uppermost aquifer is at least 10 feet below ground surface). Land Application Land application of E&P wastes is generally considered a disposal method, however an exception to classify the use as beneficial may be granted by KDHE Bureau of Waste Management with proper documentation. Water based drilling muds and cuttings are eligible for land application but brine and completion fluids are not eligible. Prior to application, KDHE requires information on the material to be applied as well as the characteristics of the application area, and a soil loading analysis. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in these regulations. Commercial recycling and reclamation facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. NORM and TENORM TENORM is not regulated in Kansas. Land spreading is an acceptable form of NORM disposal when the maximum predicted NORM level is no more than 1.5 times the highest NORM level found in the drilling waste samples and the maximum predicted NORM level is no more than 370 Bq/kg (10 pCi/g). C.16. Montana In 2016, Montana accounted for 0.4% of the U.S. oil and gas production as indicated by the U.S. Energy Information Agency. Wells include a large number of conventional reserves as well as unconventional Bakken production in the eastern part of the state. The Montana Board of Oil and Gas Conservation within the Natural Resources and Conservation Department regulates oil and natural gas production, and Montana Department of Environmental Quality (MDEQ) solid waste regulations address TENORM related to oil and gas production, in the state. The Montana Department of Environmental Quality, Solid Waste Management Section regulates solid/hazardous waste. Updates to the oil and gas Management of Exploration, Development and Production Wastes Appendix C: State Programs C-50 regulations were made in 2009; these did not address pits and other waste management operations but rather clarified select definitions, production tests, and reporting. Additional updates in 2011 and 2018 addressed hydraulic fracturing and well stimulation activities. Most regulations were last updated or promulgated in 1992. As of 2018, revisions were being considered to TENORM rules in Montana. Table C-16 provides a summary of the regulations identified for E&P wastes in Montana. Table C-16. Summary of Regulations for E&P Wastes in Montana Topic Area Summary Definitions Regulations contain 81 regulatory definitions but few related to E&P waste. The definition of earthen pits includes reserve pits, skimming pits, settling pits, produced water pits, percolation pits, evaporation pits, emergency pits, and workover pit. Waste Unit Location Requirements Regulations are overarching for all pits with respect to floodplains and dispersed in regulations for surface water and groundwater. Endangered species are not specifically addressed in these regulations. Location restrictions are not provided; however, regulations require that earthen pits or ponds that receive produced water containing more than 15,000 ppm TDS must be constructed above the high groundwater table. Tank Requirements The only tank requirement specified is netting for “open storage vessels.” No other tank requirements are included in the regulations. Pit Construction and Operation Requirements Permits are required for earthen pits and produced water pits with more than 15,000 ppm TDS. Synthetic liners are required for production pits and oil/salt mud reserve pits. Additional requirements include a minimum freeboard of 3 feet, fencing and netting, as well as requirements for temporary pits. Signage is required as part of the well site but not for pits specifically. Requirements are not provided for leak detection/monitoring, minimum depth to groundwater, berms or secondary containment, run-on/run-off controls, groundwater monitoring, inspection, discharge permits, non-commercial fluid recycling pits or centralized pits. Pit Closure Requirements Regulations specify liquids removal, solids removal and schedule for pit closure. Inspection and sampling for pit closure are not specifically addressed. Financial security for pit closure is a general requirement for bonding under the application for permit to drill. Spill Notification Spill notification is not specifically addressed in the state regulations. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills E&P waste disposal is allowed at municipal landfills and possibly other radioactive waste facilities. Testing is only required for TENORM prior to disposal. Use of waste as daily cover is not specifically addressed in the regulations. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Waste minimization and management activities, such as closed loop drilling and produced water recycling, are not specifically addressed in these regulations. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-51 Table C-16. Summary of Regulations for E&P Wastes in Montana Topic Area NORM and TENORM Summary TENORM is addressed by regulations for the MDEQ solid waste program. Disposal is allowed at permitted TENORM landfills. Testing/screening is required as acceptable radioactivity levels depend upon the permit for each facility. Action plan/management plan and storage requirements are not specifically addressed by these regulations. C.17. Mississippi According to the U.S. Energy Information Agency, Mississippi accounted for approximately 0.4% of the nation’s oil and gas production in 2016. While some oil production comes from conventional vertical wells, the bulk of Mississippi’s production (both oil and gas) is from the unconventional Tuscaloosa Shale in the southern part of the state. Wells in the Tuscaloosa are deep and the play is still in its early stages. The State Oil and Gas Board (OGB) regulates oil and natural gas production in the state. The Department of Environmental Quality, Waste Division is responsible for management of solid and hazardous waste. NORM related to oil and natural gas production is regulated by the Oil and Gas Board. Oil and Gas Conservation statutes (Title 53, Chapters 1 and 3) contain mostly administrative rules related to permits, spacing, fees and authority of the OGB and were last updated in 2015. Statewide Rules and Regulations (Order No. 201-51, Rules 1 through 69) contain the detailed requirements for waste management including Rules 68 and 69 covering NORM-contaminated waste. Rule 61, relating to berms crude and saltwater tanks was updated in 2015 and Rule 68 related to NORM was updated in 2017. The Rulebook also contains 12 rules applicable to state offshore submerged lands (OS-1 through OS-12). Title 17 (Solid Waste) includes pertinent E&P waste definitions and authorizes the OGB to regulate oilfield wastes. The most recent date of revision for regulations was not always clear in the Rulebook, because the source often only referred to the original authorizing act. Table C-17 provides a summary of the regulations identified for E&P wastes in Mississippi. Table C-17. Summary of Regulations for E&P Wastes in Mississippi Topic Area Definitions Summary Approximately 20 definitions are provided in Title 53, Chapter 1 and 36 definitions are included in Rule 2 regarding oil and gas operations. Some rules include additional definitions. Five types of earthen pits are discussed: temporary salt water storage pits, emergency pits, burn pits, well test pits and drilling reserve pit (mud pits). Regulations are often performance based (e.g. “Mud Pits used in connection with drilling operations shall be sited and constructed so as to prevent the escape of any of the pit contents”) and leave much of the technical requirements to the Supervisor and inspectors for approval. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-52 Table C-17. Summary of Regulations for E&P Wastes in Mississippi Topic Area Waste Unit Location Requirements Tank Requirements Summary Location and siting requirements for waste management units (pits and tanks) are general in nature. No specific setback distances from surface water, groundwater, floodplains or sensitive habitats were found in the regulations. These criteria may be specified in well and pit permits but were unavailable for review. Groundwater and surface water are addressed by the general requirement for non-polluting activities: “rules and regulations are hereby promulgated to prevent waste by pollution of air, fresh waters and soils. These rules shall be effective throughout the state of Mississippi and are for the purpose of prevention of waste by pollution of air, fresh waters and soils." Regulations do not address endangered species and only floodplains in NORM landfarms. Landfarming of NORM waste cannot be within 300 feet of an occupied dwelling, within 25-year floodplain or in an area with less than 5 feet to groundwater. Unlike many states, Mississippi tank regulations specifically address saltwater tanks. Each permanent oil and/or saltwater tank or battery of oil and/or saltwater tanks require a dike (or firewall) with 150% capacity of the largest tank. No specific construction requirements are provided, but the dike (or firewall) should be constructed of impermeable material. Fencing is not allowed for tanks and netting is not mentioned.C6 Modular large volume tanks, tank monitoring and permits regarding tank bottom removal are not specifically addressed in the regulations. Construction and operation requirements are provided for earthen pits,C7 which include temporary salt water storage pits, emergency pits, burn pits, well test pits and drilling reserve pit (mud pits). Permits are issued for such pits, with the exception of drilling reserve pit (mud pits), which are included in the APD. Temporary salt water storage pits require lining with an impervious material acceptable to the Supervisor; liners are not mentioned for other pit types. Pit Construction and Operation Requirements Berm requirements and run-on/run-off controls are general stating the pit shall be protected from surface waters by dikes and drainage ditches. Fencing is not allowed (see footnote for tanks below). General performance-based requirements are provided for all five types of pits, including construction “so as to prevent the escape of any of the contents”, and maintaining fluid levels (freeboard) of 1 to 2 feet, all pits require a sign placed conspicuously near the pit. Inspections are not required but a representative of the State Oil and Gas Board must be given an opportunity to inspect a pit prior to use. Discharge permits are not required for reserve pits. Pit fluids may be discharged to the land surface and/or streams, after notifying the Oil and Gas Board field representative, if mud contents meet specified criteria and proper approval is secured from the Department of Natural Resources. C6) The regulation specifically prohibits facilities from having restricted access with fencing and either locked or unlocked gates. The regulation explains that insuring that this agency’s Field Inspectors and other agency personnel have unrestricted access to all oil and gas wells, tanks, tank batteries and related oil and gas exploration and production facilities on a 24-hour a day, 7- day a week basis for inspection and regulatory enforcement purposes. C7) The introduction of the earthen pits rule notes that earthen pits are to be phased out, unless done in accordance with the regulations. The term earthen pit is not defined in the regulations so it is unclear if it refers to unlined pits or any excavated area used for storage. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-53 Table C-17. Summary of Regulations for E&P Wastes in Mississippi Topic Area Pit Construction and Operation Requirements (Cont.) Summary Leak detection/monitoring, minimum depth to groundwater, netting, groundwater monitoring, non-commercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. Onshore regulations state that impervious containers be used in lieu of pits in areas where it is impossible or impractical to construct a pit, or to protect waters or environmental resources. Where impervious containers are used, the contents must be properly disposed of within ninety days following usage. Pit Closure Requirements Liquids removal is required prior to pit closure, and solids removal is not mentioned. Pit closure consists of removal of fluids, backfilling, leveling and compacting for all pits. A closure schedule is only provided for Reserve Pits, which states they should be closed within 3 months of completion of drilling. Inspections are required for Emergency Pits within 2 weeks after the emergency period to ensure the pit contains no more than 2 feet of water and is ready for future emergency use. Financial assurance is required for wells, not pits specifically. Sampling is not specifically addressed in the regulations. Spill Notification Spill notification and corrective action are included in these regulations for offshore wells only.C8 The offshore rules require recording the cause, size of spill and action taken. The record must be maintained and available for inspection by the Supervisor All spills or leakage of oil and liquid pollutants of one barrel or more must be reported orally to the Supervisor “without delay” and then be confirmed in writing. Corrective Action Regulations state that corrective action should be taken immediately and in accordance with the approved emergency plan. Modifications to plans may be conducted as directed by the Supervisor. Off-site Landfills Off-site landfills are not specifically addressed in the regulations. The regulations allow downhole disposal of mud and other deleterious substances and allow other disposal methods to be approved by the Supervisor. Solid waste regulations exclude E&P wastes from solid waste regulations as well as in definitions of municipal and industrial waste, but U.S. DOE (1997) reported 10 municipal landfills that accept E&P waste. Land Application Land application of NORM-contaminated wastes is allowed in Mississippi, however the rule appears to exclude NORM impacted sludge, tank bottoms, drilling muds, drill cuttings or other materials, thus only allowing scale from equipment and NORM contaminated soils. Waste with ambient exposure rates in excess of 600 microR per hour cannot be land applied and the ambient exposure rate in the impacted area should not exceed eight (8) microR per hour above background or exceed a concentration of Radium 226 or Radium 228 of 5 pCi/g above background. These values are exceeded the operator shall take “appropriate remedial or corrective action. Land application restrictions include distance to groundwater (five feet), proximity to the 25-year floodplain, and distance from inhabited dwelling (300 feet). Beneficial Use No beneficial uses of E&P wastes such as road spreading are provided in the regulations but solid waste regulations allow Mississippi Department of Environmental Quality to make a determination that allows for the beneficial use of eligible nonhazardous solid wastes in the state, if applicants make a formal request. C8) It is unclear if the offshore spill regulations provided in OS-8 (Prevention of Waste, including Pollution, and Waste Disposal) are also applicable to onshore wells. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-54 Table C-17. Summary of Regulations for E&P Wastes in Mississippi Topic Area Summary Waste Minimization/ Management No regulations regarding waste minimization, closed loop drilling or produced water recycling were identified. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the oil and gas regulations. They are not explicitly addressed in the solid waste regulations. NORM in Mississippi is addressed by the Division of Radiological Health within the State Department of Health, as well as Rules 68 and 69 for NORM-contaminated wastes relating to oil and gas activities. Under the Radiation Division, NORM is exempt from regulations if less than 5 picocuries per gram of radium - 226 or radium - 228 above background; or, concentrations less than 30 picocuries per gram of technologically enhanced radium-226 or radium-228. NORM disposal requires a permit, which is issued for a period of time that is “reasonably necessary to complete the disposal activity not to exceed 5 years.” NORM waste must be from oil and/or gas-related activities conducted within the territorial limits of the State. NORM and TENORM Acceptable methods of NORM disposal include (1) Placement between cement plugs; (2) Encapsulation in pipe then placed between cement plugs; (3) Mixed with gel or mud (slurried) and placed between cement plugs; (4) Slurried then placed into a formation; (5) Surface land spreading; (6) Subsurface land spreading; or (7) Disposal offsite at a licensed, low level radioactive waste or NORM disposal facility. Notification to the Supervisor is required at least 48 hours prior to beginning disposal operations, to allow a representative to observe, inspect the operation. Conditions for disposal by land spreading of NORM waste were described above. Limitations for other disposal methods were not provided. An action plan/management plan and storage requirements are not specifically addressed in the regulations. C.18. Michigan In 2016, Michigan accounted for approximately 0.3% of the nation’s oil and gas production according to data from the U.S. Energy Information Agency. Production is from a combination of historic conventional fields and unconventional reserves including the Antrim Shale and more recent discoveries in the deeper Collingwood and Utica shales. The Department of Environmental Quality (DEQ), Office of Oil, Gas and Minerals Division regulates oil and natural gas production in the state. The DEQ is also responsible for management of solid and hazardous waste, and NORM waste related to oil and natural gas production is regulated by its Office of Waste Management and Radiological Protection. Oil and gas regulations include Oil and Gas Operations (Rule 324, most recently amended in 2015) and Ionizing Radiation Rules for Radioactive Material (Rule 325, most recently amended in 2016). Michigan DEQ developed “Cleanup and Disposal Guidelines for Sites Contaminated with Radium-226" in November 2013. Table C-18 provides a summary of the regulations identified for E&P wastes in Michigan. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-55 Table C-18. Summary of Regulations for E&P Wastes in Michigan Topic Area Summary Definitions Approximately 50 definitions are provided in Rule 324 and 80 are included in Rule 325. Some sections include additional definitions. Drilling mud pits are the main pit type regulated, but flare pits and fresh water storage pits are mentioned in the regulations. The term “earthen pit” is used in the regulations but it is not defined. Based on context it appears to refer to unlined pits. Waste Unit Location Requirements The APD requires identification of floodplains, surface waters, rivers, and endangered species within 1,320 feet of the proposed well location but does not restrict siting based on these criteria. An environmental assessment is required to be submitted as part of the APD. C9 Regulations provide setback distances for siting of wells and certain equipment (well separators, storage tanks, and treatment equipment) near public water supply wells, but does not address surface water. There is a general requirement for oil and gas operations to not be conducted “at a location where it is likely that a substance may escape in a quantity sufficient to pollute the air, soil, surface waters, or groundwaters.” Regulations do not address siting or locations relative to endangered species or floodplains. Tank Requirements Surface facilities, including tanks, require a hydrogeological investigation of the facility area to establish local background groundwater quality prior to construction. Secondary containment (dikes or firewalls) is required and must be have a capacity 150% of a tank or tank battery. Secondary containment areas must have a leak monitoring system of either a groundwater monitor well or tertiary containment. Tanks that contain hydrocarbons or brine, or both, must be elevated and placed on impervious pads or constructed so that any leakage can be easily detected. Operators must inspect primary and secondary containment at surface facilities (including tanks) at least once per week. Netting for open tanks, modular large volume tanks, construction materials and permits regarding tank bottom removal are not specifically addressed in the regulations. Construction and operation requirements for drill mud pits are based on pit contents and formations drilled, and permits are required. Solid salt cuttings are not allowed in pits. Machine oil, refuse, completion and test fluids, liquid hydrocarbons, or other materials may not be placed in lined pits. Earthen pits may not be used for E&P waste, waste oil or tank bottoms. Impoundments for storage of fresh water (not wastes) are allowed for hydraulic fracturing, but tanks are required for containment of all flowback fluids. Pit Construction and Operation Requirements Drilling mud pits may not be constructed unless depth to groundwater is greater than 4 feet, and requirements for liners include 20-mil virgin PVC material, no seams, and large enough to encompass the drilling mud tank, salt washer and shale shaker. Pits must have round corners and slope of less than 20 degrees. Leak detection and monitoring is for the well site or hydraulic fracturing operations and not required for pits specifically. Fencing is required if a drilling mud pit is not closed immediately after drilling completion. Signage is required for a well or surface facility but not pits specifically. Discharge permits are required if discharges to the air, surface waters, or groundwater of the state are likely to occur at a surface facility. C9) The Environmental Impact Assessment is a 3 page form (Form 7200-19) that requires information on the impacts and mitigations for proposed drilling program and disposal of drilling wastes and the surface facilities to be use for production. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-56 Table C-18. Summary of Regulations for E&P Wastes in Michigan Topic Area Pit Construction and Operation Requirements (Cont.) Pit Closure Requirements Summary Netting, freeboard, berms, run-on/run-off controls, inspections and non-commercial fluid recycling pits are not specifically addressed in the regulations. Centralized production facilities are mentioned but centralized pits are not. The application process allows the Supervisor to evaluate permit applications based on the site-specific conditions and require any necessary controls to avoid or control pollution. Liquids removal is required prior to pit closure. Solids removal is not required, and all drilling mud pits shall be stiffened before encapsulation, and the liner folded over the waste prior to covering with soil. Closure specifications for flare pits are not described in the regulations. Drilling mud pits should be closed “as soon as practical after drilling completion but not more than 6 months after drilling completion.” Financial responsibility or conformance bond is required for wells, not pits specifically. Inspection and sampling during pit closure is not specifically addressed in the regulations. Spill Notification Spill notification requires owners to “promptly report and record all reportable losses, spills, and releases of brine, crude oil, oil or gas field waste, products and chemicals used in association with oil and gas exploration, production, disposal, or development.” Corrective Action Corrective action details should be in an approved spill or loss response and remedial action plan that is put on file before a facility is used. Follow-up requirements after the corrective action are not specified. Off-site Landfills No prohibition for offsite disposal of E&P wastes was found in the Solid Waste or Oil and Gas regulations but off-site landfilling was not specifically identified as a disposal method. Land Application Land application of oil and gas-related wastes is not allowed in Michigan Beneficial Use Roadspreading of brine may be approved by the Supervisor, however brine may not be used by the well owner and must be transferred to another party for use. Concentration limits are provided for hydrogen sulfide, calcium and BTEX, and annual testing of the brine source (tanks) is required. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in the state regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the state regulations. NORM wastes relating to oil and gas activities are regulated by the Department of Environmental Quality, Waste Management and Radiological Protection Division. Oil and gas regulations in the state do not address NORM waste. NORM and TENORM Downhole disposal is allowed for well plugging and abandonment waste (i.e., pipe scale). Disposal of other NORM waste depends on the concentration, and testing is required prior to disposal. Wastes below 50 pCi/g Ra-226 may be disposed in a hazardous waste or Type 2 landfill and wastes greater than 50 pCi/g at a licensed radioactive waste facility. An action plan/management plan and storage requirements are not specifically addressed in the regulations. C.19. Virginia In 2016, Virginia accounted for approximately 0.3% of the nation’s oil and gas production according to data from the U.S. Energy Information Agency. All current production is from the southwest part of the state where oil is produced from conventional reservoirs and most gas is produced from Management of Exploration, Development and Production Wastes Appendix C: State Programs C-57 unconventional coalbed methane wells. Virginia has the potential for future exploitation of unconventional shale and tight gas resources. The Department of Mines and Energy regulates oil and natural gas production in the state. The Department of Environmental Protection, along with the Department of Mines and Energy are responsible for management of solid and hazardous waste. TENORM waste related to oil and natural gas production is regulated by the Department of Health. Table C-19 provides a summary of the regulations identified for E&P wastes in Virginia. Table C-19. Summary of Regulations for E&P Wastes in Virginia Topic Area Summary Approximately 90 definitions are provided in Chapter 150 of the Virginia Gas and Oil Regulation. Specific pit types were not discussed. Definitions Waste Unit Location Requirements Most of the oil and gas regulations reviewed in the Virginia Gas and Oil Regulation (Chapter 150) became effective/amended in 2013 or 2016. Most of the TENORM regulations (Sections 3470 through 3560 of Chapter 481, Virginia Radiation Protection Regulations) were issued in September 2006 or amended in June 2008. Setback and location requirements related to groundwater and surface water are only addressed with respect to land application of pit and produced fluids. Regulations do not address endangered species or floodplains. Wells have a residential setback of 200 feet from an inhabited building, unless approved by the director. There are no specific setback requirements for waste units. Secondary containment for tanks are required to have a capacity 1-1/2 times the volume of the largest tank, be maintained in good condition and kept free of brush, water, oil or other fluids. Tank Requirements Construction details are not included, but a general requirement states that tanks should be “designed and constructed to contain the fluids to be stored in the tanks and prevent unauthorized discharge of fluids.” Inspections are required at least annually for tanks and tank installations. Netting for open tanks, modular large volume tanks and permits regarding tank bottom removal are not specifically addressed in the regulations. Specific pit types are not provided in the regulations, and all pits are considered temporary. Permits are not required for pits, but are included as part of the general well permit. Pit Construction and Operation Requirements Construction requirements for pits include a liner of 10 mil or thicker high-density polyethylene or its equivalent and a minimum freeboard of 2 feet. “Pits may not be used as erosion and sediment control structures or storm water management structures, and surface drainage may not be directed into a pit.” Specific secondary containment/berm requirements are for the entire site, not pit-specific. Fencing is required to secure the site from the public and wildlife. Signage is also required for the site, not pits specifically. Groundwater monitoring is required for the site, and each well permit must include a groundwater plan that consists of initial baseline groundwater sampling and testing followed by subsequent sampling and testing after pit installation. Netting, minimum depth to groundwater, leak detection/monitoring, inspections, discharge permits, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-58 Table C-19. Summary of Regulations for E&P Wastes in Virginia Topic Area Summary Pit Closure Requirements All free liquids must be removed prior to pit closure. Drill cuttings and solids may remain in the on-site pit for disposal, and testing is not required. Regulations state that pits should be reclaimed within 180 days. Financial security is required for the site, not pits specifically. Inspections are not specifically addressed in the regulations. Spill Notification If the lining or pit fail, notification should be given by the quickest available means, and operations shall cease until the liner and pit are repaired or rebuilt. Other onsite and offsite leaks require oral and written reporting as part of the monthly report. Corrective Action On-site corrective action for spills should be “consistent with the requirements of an abatement plan, if any has been set, in a notice of violation or closure, emergency or other order issued by the director.” Spills reported in the mothy report must include a description of the corrective actions taken. Off-site Landfills Disposal of E&P waste at a permitted offsite facility (including landfills) is the recommended practice for all other solid waste from gas, oil or geophysical operations. Land Application Land application of oil and gas-related wastes in Virginia does not require a permit. Fluids to be land-applied must meet groundwater criteria (alkalinity, chloride, iron, manganese, oil and grease, pH and SAR). Site conditions, such as slope, soils and vegetation should be considered when determining the rate and volume of land application at each site. Fluids may not be applied if the ground is saturated, frozen or snow-covered. Fluids also shall not be applied closer than 25 feet from highways or property lines, closer than 50 feet from surface watercourses, wetlands, natural rock outcrops, or sinkholes, closer than 100 feet from water supply wells or springs. Beneficial Use Virginia has beneficial use regulations, which may be applicable but are not specific for E&P waste. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in the regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the regulations. TENORM wastes relating to oil and gas activities are regulated by the Department of Health. TENORM is exempt from such regulations if any combination of Ra-226 and Ra228 is less than 5 pCi/g excluding natural background. Oil and gas regulations in the state do not address TENORM waste. NORM and TENORM TENORM waste shall be disposed in a facility licensed under requirements for uranium and thorium byproduct materials. Alternate methods of disposal may be authorized. An action plan/management plan, on-site or landfill testing/screening requirements, and storage requirements are not specifically addressed in the regulations. C.20. Kentucky According to the U.S. Energy Information Agency, in 2016, Kentucky accounted for approximately 0.2% of the US oil and gas production. Oil and gas production is regulated by the Kentucky Cabinet for Energy and Environment, Department of Natural Resources, Oil & Gas Division. Wastes from oil and gas facilities and disposal of wastes offsite are both addressed by the Kentucky Cabinet for Energy and Management of Exploration, Development and Production Wastes Appendix C: State Programs C-59 Environment, Department of Environmental Protection. TENORM is regulated by the Kentucky Cabinet for Health and Family Services. Oil and gas regulations were most recently updated in 2007, and solid waste regulations regarding exemptions for special wastes (includes E&P wastes) were updated in 2016. Table C-20 provides a summary of the regulations identified for E&P wastes in Kentucky. Table C-20. Summary of Regulations for E&P Wastes in Kentucky Topic Area Summary Definitions Water pollution control regulations for oil and gas facilities (401 KAR 5:090) include 29 definitions, and o not include definitions for individual pit types or definition of E&P waste. Definitions for the following pit types are provided in the subsections of oil and gas regulations: holding pits for produced water and drilling pits for fluids other than produced water associated with well drilling, construction, acidizing or fracturing an oil or gas well. Waste Unit Location Requirements Overarching regulations for waste sites and facilities in the solid waste regulations address floodplains, endangered species, surface water and groundwater. Special waste landfills have setback requirements (for example, 100 feet from the property line or 250 feet of an intermittent or perennial stream unless a water quality certification has been issued). Minimum depth to groundwater for waste units is not specified. Tank Requirements Requirements for tanks are not provided in these regulations. Best management practice includes recycling of tank bottoms as waste oil. Pit Construction and Operation Requirements Holding pits and drilling pits are specified in these regulations and are covered under permits-by-rule. Such pits may not be used for the ultimate disposal of produced waters. Holding pits must be designed with a synthetic liner (20 mils or equivalent), a continuous bermed area at least two feet above ground level, and a minimum freeboard of one foot. Regulations require all surface water to be diverted away from the holding pit. Discharge permits are required for produced water. Groundwater monitoring is required for special waste sites and signage is required for general well sties, however, neither is for pits specifically. Inspections for pits are not specified, but the Cabinet may inspect any oil and gas facility. Requirements are not provided for leak detection/monitoring, fencing, netting, minimum depth to groundwater, temporary pits, non-commercial fluid recycling pits or centralized pits. Pit Closure Requirements Oil and Gas Well Operator’s Manual (Department for Natural Resources, Division of Oil & Gas) indicates that solid and liquid wastes shall be removed from pits prior to closure. The Manual also provides a closure timeframe of 30 days. Details about inspection and sampling are not included. Note: this information is based on a manual, not regulations. A general APD bond is required for special waste landfills but not pits specifically. Spill Notification Operators must develop and implement Spill Prevention Control and Countermeasure plans as required, and report spills, discharges and bypasses as necessary. Corrective Action Corrective action is not specifically addressed in the regulations. Off-site Landfills E&P waste is allowed at special waste landfills and other unspecified permitted facilities. Testing of waste and use as a daily cover are not specifically addressed in the regulations. Land Application Special waste, including E&P wastes, may be applied at landfarming or composting facilities. An application is required. Beneficial Use Beneficial reuse/brine spreading is not allowed. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-60 Table C-20. Summary of Regulations for E&P Wastes in Kentucky Topic Area Summary Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in these regulations. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. NORM and TENORM TENORM is regulated by the Kentucky Cabinet of Health and Family Services. Oil and gas regulations only address the downhole disposal of TENORM. Testing/screening is required, and waste profile/manifest is necessary for possession and transportation of TENORM. The type of landfill, well or low-level radioactive waste disposal facility depends on ranges of activity concentration. An activity concentration greater than 200 pCi/g of combined Ra-226 and Ra-228 in a landfill in Kentucky shall be prohibited. C.21. Illinois In 2016, Illinois accounted for approximately 0.1% of the nation’s oil and gas production according to U.S. Energy Information Agency data. Oil is produced from conventional reservoirs in the southern part of the state, and only a small amount of gas is produced. Most production is from stripper wells, but there is a potential for future exploration of unconventional reserves in the deep New Albany Shale. The Department of Natural Resources, Oil and Gas Program regulates oil and natural gas production in the state. The Illinois Environmental Protection Agency is responsible for management of solid and hazardous waste. NORM waste related to oil and natural gas production is regulated by the Illinois Environmental Protection Agency, Emergency Management Agency, and Central Midwest Interstate Low-Level Radioactive Waste Commission. Table C-21 provides a summary of the regulations identified for E&P wastes in Illinois. Table C-21. Summary of Regulations for E&P Wastes in Illinois Topic Area Definitions Summary Approximately 50 definitions are provided in Section 240.10 of Title 62 of the Illinois Administrative Code. Additional definitions are also provided in other sections of Part 240 (The Illinois Oil and Gas Act). Several types of pits including sediment pits (used for drill cuttings), drilling fluid pits (circulation pits) reserve pits (for drilling fluid waste storage) and completion pits are discussed, along with tanks and concrete storage structures. Title 62, Chapter 1, Part 240 (The Illinois Oil and Gas Act) has an amended effective date of March 18, 2018. Part 245 (Hydraulic Fracturing Regulations) is a recent act with extensive regulations effective November 14, 2014. Waste Unit Location Requirements Concrete storage structures and tanks are prohibited within 200 feet of an existing inhabited structure, stream, body of water or marshy land. Concrete storage structures are also prohibited in floodplains. A permit is required for any tank, structure, measure or device intended or used for storage of hydraulic fracturing fluid, hydraulic fracturing flowback, or produced water within a floodplain. Protection of groundwater and surface water from discharges are addressed in the regulations but endangered species are not. Minimum depth to groundwater for waste management units is not specified. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-61 Table C-21. Summary of Regulations for E&P Wastes in Illinois Topic Area Waste Unit Location Requirements (Cont.) Summary Hydraulic fracturing regulations require assessment of the potential for seismic activity and accounting for the risks in all well drilling and operations plans. If the well is in a seismic risk zone (as defined in the regulations) the well insurance policy is required to have a rider providing coverage against loss or claims resulting from impacts from any aspect of the permitted operations following earthquakes of magnitude 4.5 or more. Secondary containment (dikes) for tanks should be have a capacity 1-1/2 times the volume of the largest tank. Construction specifications for tanks are general and indicate materials should be compatible with the expected fluids being contained and netting is required for tanks. Tank Requirements Modular large volume tanks and tank monitoring are not specifically addressed in the regulations. Permits for tank bottom removal are not required, but haulers of liquid oilfield wastes (including tan bottoms) must be permitted. Crude oil bottom sediments may be disposed of in at permitted special waste landfills, injected at a permitted facility, bioremediated by landfarming or used for road oiling on the lease (if approved). Specific pit types include drilling, reserve, sediment, circulation, completion and workover/plugging, and production pits, and permits are required. Pits for freshwater and saltwater/oil drilling fluids have separate regulations. Pit Construction and Operation Requirements Liners are not required for fresh water drilling pits but other pit types require a synthetic flexible liner that is at least 30 mils in thickness and compatible with the fluid contained. Leak detection/monitoring, fencing, netting, run-on and run-off controls, groundwater monitoring and inspections are required. A permit is required to discharge waste onto the surrounding land surface or into a body of water. Minimum depth to groundwater, freeboard and berm requirements, signage, temporary pit requirements, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. Pit Closure Requirements All oilfield brine and produced waters shall be removed and disposed in a Class II UIC well. Fresh water drilling fluid wastes may be disposed of by on-site burial or surface application in accordance with the regulations. Saltwater and oil-based muds can be buried onsite but must be enclosed in the liner and covered with 5 feet of soil. Pit closure inspections, sampling and financial security are not specifically addressed in the regulations. Spill Notification Immediate notification is required for spills of crude oil in excess of 1 barrel, or produced water in excess of 5 barrels, onto the surface of the land; and all crude oil spills, regardless of amount, which enter streams, rivers, ponds, lakes, wetlands or other bodies of water. For saltwater spills water must be removed and disposed in permitted injection wells and the area treated with lime immediately. Loading rate and tilling requirements for lime are provided in the regulations. Corrective Action Off-site Landfills Remediation requirements are presented separately for crude oil spills and produced water spills. For saltwater spills, the Department will determine if additional remediation action needs to be taken by the permittee, which may include flushing of the area with freshwater, the addition of organic material (e.g., peat moss, straw), additional chemical treatment, additional disking the soil, or soil removal. Liquid oilfield waste, including tank bottoms and other RCRA exempt wastes, can be disposed of at special waste landfills. Special Waste landfills fall under the Inert Waste landfill construction and operation requirements and are subject to stringent siting standards and require liners, and groundwater monitoring. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-62 Table C-21. Summary of Regulations for E&P Wastes in Illinois Topic Area Land Application Beneficial Use Summary Crude oil bottom sediments may be bioremediated on-site through land spreading. Requirements for land spreading include addition of fertilizer and lime, tilling, watering to promote plant growth and limit runoff. Lease road oiling is allowed and requires a permit and should not be conducted when the ground is frozen or during precipitation events, or in areas subject to frequent flooding. Material used for lease road oiling must contain less than 10% produced water. Beneficial use of brine is not specifically addressed in the regulations. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in the regulations. Commercial Recycling and Reclamation Facilities The recently added hydraulic fracturing regulations recommend recycling of flowback and produced water. Requirements for commercial water or other waste recycling facilities are not provided in the regulations. NORM waste related to oil and natural gas production is regulated by the Illinois Environmental Protection Agency, Emergency Management Agency, and Central Midwest Interstate Low-Level Radioactive Waste Commission. Oil and gas regulations in the state do not address NORM waste. NORM and TENORM E&P waste is treated as a low-level radioactive waste and managed under the Commission's Regional Management Plan. Off-site disposal of NORM waste is permitted in non-hazardous special waste landfills if NORM is at background levels. If greater than background levels, disposal may be required at a waste facility permitted by the Illinois Department of Nuclear Safety. Residue containing NORM from concrete storage structures may also require disposal at a waste facility permitted by the Illinois Department of Nuclear Safety. Wells targeting black shale formations (New Albany) are subject to additional regulations due to the potential for elevated radioactivity content of the cuttings and fluids. Permits required developing a radioactive materials management strategy to test for and identify, manage, transport and dispose of any radioactive materials utilized or generated during the course of operations. Testing of drill cuttings for radioactivity is required. Drilling fluid, drilling cuttings and drilling waste from any black shale zones that test positive for levels of radioactive contamination shall not be stored in open pits and must be disposed of offsite at a permitted facility. C.22. Indiana In 2016, Indiana produced approximately 0.04% of total U.S. oil and gas production, according to the U.S. Energy Information Agency. The Division of Oil and Gas within the Indiana Department of Natural Resources regulates oil and natural gas production, as well as NORM related to oil and gas production, in the state. The Indiana Department of Environmental Management regulates solid and hazardous wastes. The oil and gas regulations, Title 29 (312 IAC 29), were promulgated in 2017. Table C-22 provides a summary of the regulations identified for E&P wastes in Indiana. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-63 Table C-22. Summary of Regulations for E&P Wastes in Indiana Topic Area Summary Definitions The oil and gas regulations include 134 definitions including many related waste management. The definition of “E&P waste” is very general and does not reference the RCRA exemption. Several entries relate to hydraulic fracturing, stimulation, and NORM wastes. Definitions are provided for circulation pit, completion pit, production fluid storage pit, reserve pit, workover pit, and concrete production fluid storage structures. Waste Unit Location Requirements Requirements for facility locations in floodplains, and proximity to surface water and groundwater are dispersed throughout the subsections in the regulations. Endangered species are not specifically addressed in these regulations. Location restrictions are provided (for example, pits shall not be located within 200 feet of an occupied dwelling or a water body). Pits must also be located 3 feet above the seasonally high groundwater table. Tank Requirements Indiana regulations include detailed technical and operational requirements for tank batteries. The regulations address tank and berm design, tank construction materials, and the treatment of storm water within secondary containment. The regulations specify netting for open top tanks. Pit Construction and Operation Requirements Regulations include definitions for the following types of pits: circulation pit, completion pit, production fluid storage pit, reserve pit and workover pit. Permits are required for construction of a pit in a floodway. Indiana pit and tank regulations include numerous requirements for ”concrete production fluid storage structures” , a structure not specifically regulated in other states in this study. Pits containing saltwater-based, oilbased and production fluids require synthetic liners. Construction details are provided in the regulations, and a visual inspection is required. Additional requirements for freeboard, fencing, netting, berms, run-on/run-off controls, signage and inspections are also included. Temporary pits are also addressed. Requirements are not provided for groundwater monitoring, inspection, discharge permits, non-commercial fluid recycling pits or centralized pits. Pit Closure Requirements Regulations specify liquids removal, liner removal and schedule for pit closure (within one hundred twenty (120) days after conclusion of well drilling operations or sixty (60) days of well completion operations, whichever occurs first). Inspection and sampling for pit closure are not specifically addressed. Financial security for pit closure is a general requirement for bonding under the application for permit to drill. Spill Notification Spill notification is not specifically addressed in the state regulations. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills Land Application E&P waste disposal is allowed at “permitted landfills”, including municipal solid waste landfills. Testing of waste and its use as daily cover in municipal landfills are not specifically addressed in the regulations. Water-based mud and completion fluids may be land applied. A permit is required if not applied at the lease site. Conditions for use and location restrictions are provided in the regulations, such as land application may not be performed during a precipitation event, chloride content must be less than 1,000 mg/L, and the site must be located at least 100 feet from a water body. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-64 Table C-22. Summary of Regulations for E&P Wastes in Indiana Topic Area Land Application (Cont.) Summary Crude oil and tank bottoms are allowed for oiling lease and county roads with a permit. Conditions for its use are provided in the regulations. Examples specify that road oiling shall not be conducted when the ground is frozen and the produced water content of the crude oil tank bottoms shall not be greater than 10% free water by volume. Disposal of oil and gas NORM on lease or county roads is prohibited. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling is noted in the regulations but it not specifically designated as a best management practice. Closed loop systems must be maintained in a leak-free condition when used Produced water recycling is not required. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. NORM and TENORM Oil and gas NORM waste may be disposed in plugged and abandoned wells, disposed or land applied at the lease site, or disposed at an off-site facility that is permitted to accept such waste. Notification and disposal plan are required but a permit is not. Land application limits indicate that after application and mixing, radioactivity concentration in the area may not exceed five (5) pCi/g above background of Radium-226 combined with Radium-228 or one hundred fifty (150) pCi/g above background of any other radionuclide. Additional disposal limitations/conditions are provided in the regulations. C.23. New York According to the U.S. Energy Information Agency, New York accounted for approximately 0.04% of the total US production in 2016. The New York Department of Environmental Conservation regulates oil and gas production and facilities (Division of Mineral Resources), solid waste disposal (Division of Materials Management) and NORM/TENORM/NARM (Division of Environmental Remediation). Table C-23 provides a summary of the regulations identified for E&P wastes in New York. Table C-23. Summary of Regulations for E&P Wastes in New York Topic Area Summary Definitions Only brine pits are discussed in the regulations. Other pit types are not defined. Waste Unit Location Requirements Solid waste regulations include general requirements for siting solid waste facilities. Overarching requirements include a general prohibition of pollution in oil and gas operations. General well location restrictions are 100 feet from any inhabited private dwelling house without written consent, or 150 feet from any public building and 50 feet from a public stream, river or other body of water. Minimum depth to water is not specified. Tank Requirements Tank requirements are provided for solid waste facilities, not oil and gas facilities specifically. All tanks must be chemically compatible with the waste being stored and inspections are required. If necessary, above ground tanks must have a secondary containment system designed and built to contain 110% of the volume of either the largest tank within the containment system or the total volume of all interconnected tanks, whichever is greater. A minimum freeboard of 2 feet is required if the top of the tank is open. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-65 Table C-23. Summary of Regulations for E&P Wastes in New York Topic Area Summary Tank Requirements (Cont.) Modular large volume tanks, netting, tank monitoring and tank bottom removal are not specifically addressed in the regulations. Pit Construction and Operation Requirements Drilling muds are not considered to be polluting fluids. The only pit type included in these regulations is earthen pits for brine. A “watertight material” is required for brine pits; unlined brine pits are prohibited. Permits are not required, however, the operator must submit and receive approval for a plan for the environmentally safe and proper ultimate disposal of fluids. A permit for discharge may be required depending on the disposal method. Signage is necessary for the oil and gas facility, not pits specifically. Requirements are not provided for leak detection/monitoring, fencing, netting, depth to groundwater, freeboard, berms or secondary containment, run-on/run-off controls, groundwater monitoring, signage, inspection, temporary pits, non-commercial fluid recycling pits or centralized pits. Pit Closure Requirements Pit closure should be conducted within 45 days after cessation of drilling operations, unless the Department approves an extension. No other details regarding pit closure are included in the regulations. Financial security for pits is included as part of oil and gas facility bond. Spill Notification Spill notification is addressed in the regulations. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills E&P waste disposal is allowed at a solid waste facility. It is unclear about whether testing of waste is required or if E&P waste may be used as daily cover, although it was noted that the waste may not be within 10 feet of the final cover. Land Application Land application of E&P waste is not specifically addressed in the state regulations. Beneficial Use Beneficial use of brine requires a written petition, and brine must meet specific criteria for roadspreading. Specifics are provided in the regulations for its application and usage. For example, brine application for dust control and road stabilization is prohibited between sundown and sunrise on unpaved roads and brine may not be applied directly to vegetation. Waste Minimization/ Management Waste minimization and management activities, such as closed loop drilling and produced water recycling, are not specifically addressed in these regulations. Commercial Recycling and Reclamation Facilities Commercial and stationary recycling and reclamation facilities are not specifically addressed in these regulations. NORM and TENORM New York applies the term “naturally occurring and/or accelerator-produced radioactive material (NARM)” to drill cuttings. A permit is not required for NARM disposal; however, the disposal of TENORM is more restrictive. Storage requirements and disposal limitations/conditions are extensive and difficult to navigate in the regulations. There is also a specific regulation for screening if drill cuttings are being disposed. C.24. Florida According to U.S. Energy Information Agency data, Florida accounted for approximately 0.03% of the nation’s oil and gas production in 2016. All production is from conventional reservoirs with most coming from fields located near Pensacola, and a small producing area in the southern part of the state. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-66 The Department of Environmental Protection, Division of Water Resource Management, Oil and Gas Program regulates oil and natural gas production in the state. The Division of Waste Management, Solid Waste and Recycling Program is responsible for management of solid waste. NARM waste related to oil and gas production is regulated by the Florida Department of Health, Radiation Control.C10 Table C-24 provides a summary of the regulations identified for E&P wastes in Florida. Table C-24. Summary of Regulations for E&P Wastes in Florida Topic Area Definitions Summary The oil and gas regulations are relatively concise and do not provide detailed specifications and requirements for most waste management topics. Approximately 60 definitions are provided in Chapter 62C-25 (Conservation of Oil and Gas: General). The types of pits discussed include mud pits and reserve pits. Most of the oil and gas rules (Sections 62C-25 through 29) were amended on March 24, 1996, with a few sections being amended since. Section 64E-5.101 (Definitions) in Control of Radiation Hazards was published on December 26, 2013. Waste Unit Location Requirements Tank Requirements Pit Construction and Operation Requirements Location restrictions (residential and environmental setbacks) and minimum depth to groundwater are not specifically addressed in the oil and gas regulations for any waste management units. Groundwater, surface water and endangered species are not specifically addressed in the oil and gas regulations. Solid waste regulations state “A landfill or solid waste disposal unit shall not be located in the 100-year floodplain where it will restrict the flow of the 100-year flood, reduce the temporary water storage capacity of the floodplain unless compensating storage is provided, or result in a washout of solid waste.” There are few technical requirements for tanks in the regulations. Secondary containment must be two times the capacity of the tank. General construction requirements indicate materials should be “relatively impermeable and of sufficient size and strength.” Netting, modular large volume tanks and removal of tank bottoms are not specifically addressed. A general requirement for operating facilities includes monitoring all equipment and facilities to immediately detect any leak which may cause pollution. Specific pit types addressed in the regulations include mud pits and reserve pits. Earthen pits for active drill fluids are prohibited. Sensitive areas (including wetlands and national/state forests and parks) require prefabricated tanks and drip pans for all waste fluid, or reserve pits that must be either lined with impermeable material or intermittently pumped to reduce hydrostatic head. Reserve pits should also not exceed 75% capacity to ensure adequate freeboard. General dike requirements for sites include installation of berms and run-on/run-off controls. Permits and signage for pits are part of the general APD. Leak detection/monitoring, fencing, netting, minimum depth to groundwater, groundwater monitoring, inspections, discharge permits, temporary pit requirements, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. C10) Florida uses the term naturally occurring or accelerator-produced radioactive material (NARM) in regulations, but the definition is consistent with TENORM in other states. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-67 Table C-24. Summary of Regulations for E&P Wastes in Florida Topic Area Summary Liquids and recoverable slurry must be removed from the pit and disposed either downhole or at a landfill. Pit Closure Requirements Financial security is included in the general well bond, not for pits specifically. Pit closure schedule, inspections, and sampling are not specifically addressed in the regulations. Spill Notification Spills of crude petroleum or associated fluids into the environment require immediate notification and written confirmation for spills greater than 5 barrels. Corrective Action Corrective actions should be immediate and conducted in accordance with Spill Prevention and Clean Up Plan. Off-site disposal of E&P waste is allowed, but the type of facility is not specified. Off-site Landfills Requirements for testing of waste and use of E&P wastes as daily cover are not specifically addressed in the state regulations. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in the regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the regulations. Florida Department of Health defines “NARM” as any naturally occurring or acceleratorproduced radioactive material. To meet the definition of licensing state, NARM only refers to discrete sources of NARM. Diffuse sources of NARM, which are large in volume and low in activity, are excluded from consideration by the Conference of Radiation Control Program Directors, Inc., for licensing state designation purposes. NORM and TENORM Florida has comprehensive regulations for radioactive materials, but none specifically address oil and gas or TENORM. Regulations appear to allow TENORM type materials to be disposed at permitted facilities, however specific permitting and testing requirements are unclear. An action plan/management plan, on-site or landfill testing/screening and storage requirements are not specifically addressed in the regulations. C.25. Idaho The U.S. Energy Information Agency estimated that Idaho accounted for approximately 0.01% of the nation’s oil and gas production in 2016. Oil exploration has occurred in Idaho since the early 1900’s but commercial production just started in 2016 from a small conventional gas field in southwestern Idaho. The Idaho Department of Lands, Oil and Gas Conservation Commission regulates oil and natural gas production in the state. The Oil and Gas Division serves as the administrative arm of the Commission. The Department of Environmental Quality, Waste Management and Remediation Division, Solid Waste and Hazardous Waste Programs regulate solid and hazardous waste, respectively. The Department of Environmental Quality regulates NORM/TENORM waste related to oil and natural gas production. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-68 Idaho oil and gas regulations underwent a major revision in 2012 in response to increased drilling activity. Additional changes have been made as recently as 2015 which included new regulations for pits and tanks. Department of Water Resources recently announced that it would ask the EPA to run the Class II injection program in Idaho because it is new to the industry and is the only hydrocarbonproducing state without a Class II program in place. Table C-25 provides a summary of the regulations identified for E&P wastes in Idaho. Table C-25. Summary of Regulations for E&P Wastes in Idaho Topic Area Definitions Summary Approximately 60 definitions are provided in Section 010 (Definitions) of ID07, Chapter 02 – Rules Governing Conservation of Oil and Natural Gas in the State of Idaho. Pits are defined as any excavated or constructed depression or reservoir used to contain reserve, drilling, well treatment, produced water, or other fluids at the drill site. This does not include enclosed, mobile, or portable tanks used to contain fluids. Regulations for waste management provide a combination of detailed technical specifications (pit construction, for example) and more general requirements (pit content disposal). Waste Unit Location Requirements Tank Requirements Regulations related to siting pits near floodplains, surface water and groundwater are dispersed in the oil and gas regulations. Solid waste regulations provide general overarching location and siting requirements for floodplains, surface water, groundwater and endangered species. Specific setback distances for pits are not specifically addressed in the regulations. Tank batteries cannot be placed in a recognized source water assessment or protection area, or within 300 feet of existing occupied structures, water wells, canals, ditches, natural or ordinary high water mark of surface waters, or within 50 feet of highways. Pits located in a one hundred-year floodplain must be in conformance with any applicable floodplain ordinances. A minimum depth to groundwater is not included in the regulations. Regulations state that dikes for tank batteries have a capacity of 1½ times the volume of the largest tank and a permeability of 10-9 cm/sec. Construction specifications, netting, monitoring, modular large volume tanks and removal of tank bottoms are not specifically addressed. Mud pits are specifically discussed in the oil and gas regulations. Separate requirements are provided for short-term pits (reserve, well treatment and other pits used less than 1 year) versus long-term pits (used longer than 1 year). Separate pit permits are required only if the pit is not included under the original APD. Pit Construction and Operation Requirements Liners with a thickness of 20 mils are required for reserve, well treatment and other short-term pits, while long-term pits require liners of 60 mils. All liners should have a permeability of 10-9 cm/sec. Leak detection/monitoring is required for long-term pits but not short-term ones. Fencing is required for the well site but not pits specifically. Fencing and netting are implied for pits based on “site-specific methods for excluding people, terrestrial animals, and avian wildlife from the pits.” Bermed pit walls must be a minimum of 2 feet wide at the top. Pits that have berms more than 10 feet in height or hold 50 acre-feet of fluid must comply with dam safety requirements. A minimum freeboard of 2 feet is required for pits. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-69 Table C-25. Summary of Regulations for E&P Wastes in Idaho Topic Area Summary Run-off/run-on controls and signage are required for Tier II/III solid waste facilities and groundwater monitoring is also required for Tier III facilities, not pits specifically. Pit Construction and Operation Requirements (Cont.) Short-term pits are considered temporary pits. The owner/operator must notify the Department within 24 hours of an emergency situation that requires an emergency pit. Regulations require removal of oil skims from both short term and long-term pits. Inspections, discharge permits, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. Pit Closure Requirements Liquid removal is required prior to pit closure. Pit liners and accumulated solids should be removed and testing of the solids is necessary to determine an appropriate disposal facility. After removal of the liner and solids, the pit must be inspected by the Department and remediated if there are signs of leakage. All reclamation work should be completed within 12 months of plugging and abandonment of a well or closure of other oil and gas facilities. Bonds are required for the wells/site, not for pits specifically. Spill Notification Notification is required for leaks from pits. “If a pit or closed-loop system develops a leak, or if any penetration of the pit liner occurs below the liquid’s surface, then the owner or operator shall remove all liquid above the damage or leak line within fortyeight (48) hours, notify the appropriate Department area office within forty-eight (48) hours of the discovery, and repair the damage or replace the pit liner.” Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills Off-site disposal of E&P waste is not clearly stated but appears to be allowed at nonmunicipal solid waste landfills (NMSWLF). Routine characterization of waste is required at both Tier II (low risk) and Tier III (higher risk) NMSWLF facilities. Both types of facilities have stringent design criteria and require liners and groundwater monitoring. Use of E&P waste as daily cover is not specifically addressed. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling is described as an option to pits, but not required. Produced water recycling is not specifically addressed in the regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the regulations. Idaho Board of Environmental Quality regulates NORM/TENORM related to oil and gas activities. Oil and gas regulations do not address NORM/TENORM. NORM and TENORM While the regulation is not clear for NORM/TENORM, radioactive materials can be disposed at appropriately permitted RCRA C facilities. Disposal of radioactive materials is not allowed at a municipal solid waste landfill. An action plan/management plan, on-site or landfill testing/screening and storage requirements are not specifically addressed in the regulations. C.26. Tennessee According to the U.S. Energy Information Agency, in 2016, Tennessee accounted for approximately 0.01% of the nation’s oil and gas production. Small quantities of oil and gas are produced from both Management of Exploration, Development and Production Wastes Appendix C: State Programs C-70 conventional wells and new unconventional wells targeting the Chattanooga Shale. The Department of Environment and Conservation, division of Water Resources Oil and Gas Board regulates oil and natural gas production in the state. The Department of Environment and Conservation, Division of Radiological Health regulates NORM/TENORM waste related to oil and natural gas production. Chapters 0400-51 through 0400-58 contain rules for the Oil and Gas Programs and were most recently updated in June 2013. Four sections address issues related to waste management: Definitions, Drilling, Testing and Completion, and Production. Chapter 0400-20 (Division of Radiological Health) is dated May 22, 2012. Table C-26 provides a summary of regulations identified for E&P wastes in Tennessee. Table C-26. Summary of Regulations for E&P Wastes in Tennessee Topic Area Definitions Summary Nearly 100 definitions are provided in Chapter 0400-51-01 (Definitions) of the Rules of the Oil and Gas Program. Discussion of waste management addresses only tanks and pits and is fairly brief in Chapter 0400-53-03 (Prevention of Hazards and Pollution). Regulations address hydraulic fracturing controls and chemical disclosure. The types of pits discussed include mud circulation pits, reserve pits and saltwater pits. Waste Unit Location Requirements Overarching regulations indicate wells, pits or storage facilities in wetlands or flood-prone areas are prohibited. Regulations for surface water are dispersed and state that a pit cannot be within 100 feet of the normal high-water line of any stream or lake. Pits and tanks should also be located at least 100 feet from any fire hazard or dwelling. Endangered species are not specifically addressed in the oil and gas regulations. While a minimum depth to groundwater is not specified, there is a general requirement that pits should be constructed above ground where shallow groundwater may be encountered, or closed loop drilling should be used. Tank Requirements Regulations provide a limited amount of detail and requirements for construction and operation of tanks. Secondary containment is required and should be 1½ times the capacity of the largest tank in the battery. Regulations include a diagram of an excavated tank pad and pit containment system. Construction requirements, netting, monitoring, modular large volume tanks and removal of tank bottoms are not specifically addressed in the regulations. The types of pits discussed include mud circulation and reserve pits, as well as saltwater and fracturing fluid pits. Pits for saltwater and fracturing fluids are considered temporary storage. Pit Construction and Operation Requirements Pits require synthetic liners with a minimum thickness of 10-mil thickness (or equivalent measures, such as clay). However, mud circulation and reserve pits require a liner of 20mil thickness with a 4-inch welded seam overlap. These pits also have additional minimum requirements, such as a freeboard of 2 feet, 2:1 side slopes and berm walls at least 2 feet wide. Only runoff from the immediate area may enter the pit. While no specific minimum depth to groundwater is provided, regulations state “In areas where groundwater is close enough to the surface that it will be encountered in construction of a pit, pits shall be constructed above ground, or the operator shall use a closed-loop system.” Management of Exploration, Development and Production Wastes Appendix C: State Programs C-71 Table C-26. Summary of Regulations for E&P Wastes in Tennessee Topic Area Pit Construction and Operation Requirements (Cont.) Pit Closure Requirements Summary Signage is required for the well, and groundwater monitoring (sampling drinking water wells is done at the request of the owner, and is not pits specifically. Groundwater monitoring is only required for hydraulically fractured wells that use more than 200,000 gallons of fluid. Permits, leak detection/monitoring, fencing, discharge permits, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. Pits should be drained and filled within 30 days of the initial disturbance. All drilling supplies and equipment (including liners) that are not contained and covered in the pit shall be removed from the site. Financial security is included in the general well permit, not for pits specifically. Inspections and sampling are not specifically addressed in the regulations. Spill Notification A spill of oil, saltwater, or other drilling or production associated materials requires notification within 12 hours. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills Off-site disposal of E&P waste is not specifically mentioned in the regulations. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling is a possible alternative in wetlands but is not required. As stated above, “In areas where groundwater is close enough to the surface that it will be encountered in construction of a pit, pits shall be constructed above ground, or the operator shall use a closed-loop system.” Produced water recycling is not specifically addressed in the regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the regulations. Tennessee Division of Radiological Health defines “NARM” as any naturally occurring or accelerator-produced radioactive material. It does not include byproduct, source or special nuclear material. Oil and gas regulations do not define NARM but rather reference radiation regulations. NORM and TENORM Disposal of NARM is determined on a case by case basis. ASTSWMO indicates that disposal of NARM waste is allowed in a MSWLF if less than 30 pCi/g. An action plan/management plan and on-site or landfill testing/screening are not specifically addressed in the regulations. C.27. Nevada The U.S. Energy Information Agency data indicates that Nevada accounted for less than 0.01% of the nation’s oil and gas production in 2016. There is no commercial gas production in Nevada and a very small volume of oil is produced from two shallow producing areas with fewer than 20 oil fields. The Nevada Commission on Mineral Resources, Division of Minerals, Oil and Gas – Oil and Gas Program regulates oil and natural gas production in the state. The Department of Environmental Conservation, Division of Environmental Protection regulates solid and hazardous waste. The Department of Health Management of Exploration, Development and Production Wastes Appendix C: State Programs C-72 and Human Services, Division of Public and Behavioral Health regulates NORM/TENORM waste related to oil and natural gas production. Nevada oil and gas regulations (Chapter 522) are clear but with limited details. For example, the only discussion of pits is in Chapter 522.225 containing two short paragraphs without any technical specifications. The Oil and Gas Division appears to have significant flexibility to address issues on a site-specific basis. In 2014, the oil and gas regulations were updated to include a section on hydraulic fracturing which provides a much greater level of detail and technical specifications. Table C-27 provides a summary of the regulations identified for E&P wastes in Nevada. Table C-27. Summary of Regulations for E&P Wastes in Nevada Topic Area Definitions Waste Unit Location Requirements Summary Approximately 36 definitions are provided in Chapter 522.010 (Definitions) and 522.700 (Hydraulic Fracturing) of Chapter 522 - Oil and Gas. Definitions are not provided for specific pit types or wastes. Oil and gas regulations do not provide location or setback requirements for pits. The only location or setback requirement potentially related to waste management units is that the edge of the drilling pad must not be less than 100 feet from any known perennial water source, existing water well or existing permitted structure. Dikes or fire walls are required around oil tanks located within the corporate limits of any city or town, where tanks for storage are less than 500 feet from any highway or inhabited dwelling, less than 1,000 feet from any school or church. Regulations are dispersed in the solid waste regulations and provide several location requirements. For example, Class 1 landfills are (1) allowed within 100 feet of a floodplain but must demonstrate no impact to the floodplain; (2) must not jeopardize existence or habitat for endangered species; (3) must not be within 1,000 feet of surface water; and (4) must not be within 100 feet of upper aquifer. A residential setback is not included in the regulations. As described above, dikes or fire walls are required around permanent tanks for under certain conditions, but regulations provide no further details on construction operation or protection requirements. Tank Requirements Tanks are required for containment of all fluids during hydraulic fracturing operations. Water regulations are referenced for requirements. Secondary containment requirements, construction specifications, netting, monitoring, modular large volume tanks and removal of tank bottoms are not specifically addressed. The following types of pits are mentioned in the oil and gas regulations: collecting pits, reserve pits, burning pits and pits “for storage of brines.” Pit Construction and Operation Requirements Unlined pits for oil, brines or oilfield waste are prohibited unless approved by the Division. In addition, a reserve pit for drilling liquids must not be subsequently used for the discharge of wellbore fluids during the testing of the well. Hydraulic fracturing fluids must be stored in tanks, not pits. The requirement for liners is inferred from the prohibition of unlined pits, however, no specifications are provided. Signage is required for wells, not pits specifically. Groundwater monitoring of nearby residential wells must be sampled prior to hydraulic fracturing (this requirement is not limited to pits). Management of Exploration, Development and Production Wastes Appendix C: State Programs C-73 Table C-27. Summary of Regulations for E&P Wastes in Nevada Topic Area Pit Construction and Operation Requirements (Cont.) Pit Closure Requirements Summary Permits, leak detection/monitoring, fencing, netting, depth to groundwater, freeboard and berm requirements, run-off/run-on controls, inspections, discharge permits, temporary pits, noncommercial fluid recycling pits and centralized pits are not specifically addressed in the regulations. Pit closure shall be conducted "as soon as weather and ground conditions permit, upon final abandonment and completion of the plugging of any well.” As practicable, the site should be restored to its condition when operations commenced. Financial security is included in the general well permit, not for pits specifically. Removal of pit contents, inspections and sampling are not specifically addressed in the regulations. Spill Notification Notification is required after an incident, such as a fire, lightning strike, leak, break or overflow and should include the following information: exact location of the incident; steps being taken to remedy the situation; and details about the amount of oil or gas lost, destroyed or permitted to escape. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills Off-site disposal of E&P waste is not specifically mentioned in the regulations but appears to be allowed. Testing of waste and use as daily cover were not specifically addressed. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use is not specifically addressed in the state regulations. Waste Minimization/ Management Closed loop drilling and produced water recycling are not specifically addressed in the regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the regulations. NORM and TENORM in the state currently have limited regulations; it is unclear if they are regulated under NAC 459 (Hazardous Materials). Nevada Department of Health and Human Services has an exemption for naturally occurring radioactive material that contains less than 5 picocuries (0.185 becquerel) of radium-226 per gram of material. Oil and gas regulations do not address NORM/TENORM. NORM and TENORM A licensee shall dispose of licensed radioactive material only using one of the following methods: transfer to an authorized recipient; permitted land disposal facility; by decay in storage; by release in effluents within the limits specified, or as otherwise approved. An action plan/management plan, on-site or landfill testing/screening and storage requirements are not specifically addressed in the regulations. C.28. Missouri In 2016, Missouri accounted for less than 0.01% of the nation’s oil and gas production according to the U.S. Energy Information Agency. A small number of oil wells produced from shallow conventional reservoirs, and one commercial gas well was reported in 2017. Missouri has some unconventional reserves in coalbed methane, heavy oil and tar sands. The Department of Natural Resources, Missouri Geological Survey is responsible, in part, for activities associated with oil and natural gas production in Management of Exploration, Development and Production Wastes Appendix C: State Programs C-74 the state. The Department of Natural Resources, Solid Waste Management Program is responsible for management of solid waste. NORM/TENORM is not specifically addressed in state oil and gas regulations. Many sections of the oil and as regulations were updated in 2016 including drilling and completion, production and well spacing. None of these sections appear to have regulations controlling waste management. Table C-28 provides a summary of the regulations identified for E&P wastes in Missouri. Table C-28. Summary of Regulations for E&P Wastes in Missouri Topic Area Text Approximately 70 definitions are provided in 10 CSR 50-1. No pits are defined. Definitions Missouri regulations are relatively silent on E&P waste. No technical specifications for waste management structures (pits, tanks, etc.) are provided. The review found no guidance, regulations or policies addressing criteria and siting of waste units, tanks, pits. Spill notification and corrective actions, land application, beneficial use, waste minimization, commercial recycling or NORM/TENORM. Waste Unit Location Requirements Waste unit location requirements are not specifically addressed in the state regulations. Tank Requirements Tank requirements are not specifically addressed in the state regulations. Pit Construction and Operation Requirements Pit construction and operation requirements are not specifically addressed in the state regulations. Pit Closure Requirements Pit closure requirements are not specifically addressed in the state regulations. Spill Notification Spill notification is not specifically addressed in the state regulations. Corrective Action Corrective action is not specifically addressed in the state regulations. Off-site Landfills E&P wastes are not excluded from landfills under 10 CSR 80-3.010 Design and Operation (3) Solid Waste Excluded); and may be allowed under (2) Solid Waste Accepted…”Only the following solid wastes shall be accepted for disposal in a sanitary landfill: municipal waste; bulky waste; demolition and construction wastes; brush and wood wastes; cut, chipped, or shredded tires as defined in 10 CSR 80-8; soil; rock; concrete; related inert solids relatively insoluble in water; E&P waste may be considered a Special Waste “(108) Special waste means waste which is not regulated hazardous waste, which has physical or chemical characteristics, or both, that are different from municipal, demolition, construction and wood wastes, and which potentially require special handling. Land Application Land application is not specifically addressed in the state regulations. Beneficial Use Beneficial use not specifically addressed in the state regulations. Waste Minimization/ Management Waste minimization and management are not specifically addressed in the state regulations. Commercial Recycling and Reclamation Facilities Commercial recycling and reclamation facilities are not specifically addressed in the state regulations. NORM and TENORM NORM and TENORM are not specifically addressed in the state regulations. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-75 C.29. References CalEPA (California Environmental Protection Agency). 2002. “Oil Exploration and Production Wastes Initiative.” Prepared by the Department of Toxic Substances Control. Sacramento, CA. May. PADEP (Pennsylvania Department of Environmental Protection). 2018. “Office of Oil and Gas Management: At a Glance.” TXCEQ (Texas Commission on Environmental Quality). 2014. “Management of Oil and Gas Waste at TCEQ Regulated Facilities.” [Power Point presentation]. U.S. DOE (United Stated Department of Energy). 1997. “Costs for Off-site Disposal of Nonhazardous Oil Field Wastes: Salt Caverns versus Other Disposal Methods.” Prepared by Argonne National Laboratory under Contract W-31-109-Eng-38. Argonne, IL. April. WVDEP (West Virginia Department of Environmental Protection). 2015. “Final Report on the Examination of Drill Cuttings and Related Environmental, Economic, and Technical Aspects Associated with Solid Waste Facilities in West Virginia.’” Prepared by the Marshall University Center for Environmental, Geotechnical and Applied Science. Charleston, WV. June. Management of Exploration, Development and Production Wastes Appendix C: State Programs C-76 Attachment C-1: Summary of State Regulatory Elements [Due to the large file size, this spreadsheet is maintained as a separate file.] Management of Exploration, Development and Production Wastes Appendix C: State Programs C-77 Attachment C-2: Compilation of State Regulatory Language [Due to the large file size, this spreadsheet is maintained as a separate file.] Management of Exploration, Development and Production Wastes Appendix C: State Programs C-78