# Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A96-28659 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** December 16, 1996 - **Citation:** 61 FR 66086 ## Text SUMMARY: This Clean Water Act (CWA) regulation limits the discharge of pollutants into waters of the United States and the introduction of pollutants into publicly-owned treatment works by existing and new facilities in the coastal subcategory of the oil and gas extraction point source category. This regulation establishes effluent limitations guidelines and new source performance standards (NSPS) for direct dischargers based on ``best practicable control technology currently available'' (BPT), ``best conventional pollutant control technology'' (BCT), ``best available technology economically achievable'' (BAT), and ``best available demonstrated control technology'' (BADCT) for new sources. The regulation also establishes ``pretreatment standards for new sources'' (PSNS) and ``pretreatment standards for existing sources'' (PSES) discharging their wastewaters to publicly-owned-treatment works (POTWs). In essence, this final rule codifies the current permit requirements for coastal oil and gas dischargers--except that it also requires zero discharge of offshore produced water for discharges to the main passes of the Mississippi River, applies to discharges not currently authorized by permits, and establishes limitations in Cook Inlet, Alaska which are equal to those previously established for the offshore subcategory. The major wastestreams being limited are produced water, drilling fluids, and drill cuttings. These limitations are expected to reduce discharges of conventional pollutants by 2,780,000 pounds per year, nonconventional pollutants by 1,490,000,000 pounds per year, and toxic pollutants by 228,000 pounds per year, assuming a baseline of current permit requirements. The statutory term ``toxic pollutant'' refers to a substance identified as belonging to one of the 65 families of chemicals listed in the CWA as toxic. DATES: The regulation shall become effective January 15, 1997, except for Sec. 435.45 NSPS which become effective December 16, 1996. The compliance dates for the guidelines and standards established with this rule are different. The compliance date for PSES is January 15, 1997. The compliance date for NSPS and PSNS is the date the new source begins operation. Deadlines for compliance with BPT, BCT, and BAT are established in NPDES permits. In accordance with 40 CFR part 23, this regulation shall be considered issued for the purposes of judicial review at 1 pm Eastern time on January 15, 1997. Under section 509(b)(1) of the CWA, judicial review of this regulation can be had only by filing a petition for review in the United States Court of Appeals within 120 days after the regulation is considered issued for purposes of judicial review. Under section 509(b)(2) of the CWA, the requirements in this regulation may not be challenged later in civil or criminal proceedings brought by EPA to enforce these requirements. The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of January 15, 1997. ADDRESSES: For additional engineering information contact Mr. Ronald P. Jordan, Office of Water, Engineering and Analysis Division (4303), U.S. Environmental Protection Agency, 401 M Street, SW, Washington, DC 20460, (202) 260-7115. For additional information on the economic impact analyses contact Dr. Matthew Clark, Office of Water, Engineering and Analysis Division (4303), U.S. Environmental Protection Agency, 401 M Street, SW, Washington, DC 20460, (202) 260-7192. The complete public record for this rulemaking, including EPA's responses to comments received during rulemaking, is available for review at EPA's Water Docket; Room M2616, 401 M Street SW, Washington, DC 20460. For access to Docket materials call (202) 260-3027. The Docket staff requests that interested parties call, between 9 am and 3:30 pm, for an appointment before visiting the docket. The EPA regulations at 40 CFR part 2 provide that a reasonable fee may be charged for copying. EPA notes that many documents in the record supporting these final rules have been claimed as confidential business information (CBI) and, therefore, are not included in the record that is available to the public in the Water Docket. To support the rulemaking, EPA is presenting certain information in aggregated form or is masking facility identities to preserve confidentiality claims. Further, the Agency has withheld from disclosure some data not claimed as confidential business information because release of this information could indirectly reveal information claimed to be confidential. FOR FURTHER INFORMATION CONTACT: Charles E. White, Office of Water, Engineering and Analysis Division (4303), U.S. Environmental Protection Agency, 401 M Street, SW, Washington, DC 20460, (202) 260-5411. SUPPLEMENTARY INFORMATION: Regulated Entities As described in the proposed rule (60 FR 9428, February 17, 1995), EPA has clarified the definition of the Coastal Subcategory in the Coastal Guidelines. This definition is used to describe the regulated entities. Regulated categories and entities include: ------------------------------------------------------------------------ Examples of regulated Category entities ------------------------------------------------------------------------ Industry................................. Facilities engaged in field exploration, drilling, production, and well treatment in the oil and gas industry that are in areas defined as ``coastal'' or that discharge into areas defined as ``coastal.'' ------------------------------------------------------------------------ The term ``coastal'' refers to a location in or on a water of the United States landward of the inner boundary of the territorial seas. Note that all inland bays and wetlands are included in this definition. In addition, any location in Texas or Louisiana between the Chapman Line and the inner boundary of the territorial seas is defined as ``coastal.'' The Chapman Line is defined by points of latitude and longitude within the states of Texas and Louisiana which are stated in the rule. The preceding table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities that EPA is now aware could potentially be regulated by this action. Other types of entities not listed in the table could also be regulated. To determine whether your facility is regulated by this action, you should carefully examine the applicability criteria Sec. 435.10 and Sec. 435.40 in the Regulatory Text section of the rule. If you have questions regarding the applicability of this action to a particular entity, consult the person [[Page 66087]] listed in the preceding FOR FURTHER INFORMATION CONTACT section. Alternative Baseline for Impact and Benefits Analyses Subsequent to the issuance of general permits requiring zero discharge for coastal facilities along the Gulf of Mexico, EPA received individual permit applications from Texas dischargers seeking to discharge produced water. Additionally, the U.S. Department of Energy has provided the State of Louisiana with comments and analyses suggesting a change to the Louisiana state law requiring zero discharge of produced water to open bays by January 1997. Promulgation of this rule requiring zero discharge in these areas would generally preclude issuance of permits allowing discharge. Therefore, in addition to calculating the costs, economic impacts, and pollutant removals incremental to current permit limits, EPA has calculated an alternative estimate of these factors using an ``alternative baseline.'' This ``alternative baseline'' assumes that zero discharge would no longer apply to Texas dischargers seeking individual permits and Louisiana open bay dischargers. Under this alternative baseline, this rule would reduce discharges of conventional pollutants by 11,300,000 pounds per year, nonconventional pollutants by 4,590,000,000 pounds per year, and toxic pollutants by 880,000 pounds per year. Overview The preamble describes the legal authority, background, technical and economic basis, and other aspects of the final regulation. The definitions, acronyms, and abbreviations used in this notice are defined in appendix A to the preamble. The regulatory text for amendments to 40 CFR part 435, that implements this rulemaking, follows the preamble. Organization of This Document Preamble I. Legal Authority II. Purpose and Summary of this Rulemaking A. Purpose of this Rulemaking B. Summary of the Final Coastal Guidelines III. Background A. Definitions of Guidelines and Standards B. Requirements for Promulgating, Reviewing, and Revising Guidelines and Standards C. History of the Rulemaking IV. Description of the Industry V. Major Changes to the Database for the Final Regulation A. Drilling Fluids and Drill Cuttings B. Produced Water VI. Summary of the Most Significant Regulatory Changes From Proposal VII. Basis for the Final Regulation A. Drilling Fluids, Drill Cuttings, and Dewatering Effluent B. Produced Water and Treatment, Workover, and Completion Fluids C. Produced Sand D. Deck Drainage E. Domestic Wastes F. Sanitary Wastes VIII. Economic Analysis A. Introduction B. Economic Impact Methodology C. Summary of Costs and Economic Impacts D. Cost-Effectiveness Analysis IX. Non-Water Quality Environmental Impacts A. Drilling Fluids and Cuttings B. Produced Water and Treatment, Workover and Completion Fluids X. Environmental Benefits Analysis A. Introduction B. Quantitative Estimate of Benefits C. Description of Non-Quantified Benefits XI. Related Acts of Congress, Executive Orders, and Agency Initiatives A. Pollution Prevention Act B. Paperwork Reduction Act C. Regulatory Flexibility Act D. Small Business Regulatory Enforcement Fairness Act of 1996 (Submission to Congress and the General Accounting Office) E. Unfunded Mandates Reform Act F. Executive Order 12866 (OMB Review) G. Common Sense Initiative XII. Related Rulemakings A. National Emission Standards for Hazardous Air Pollutants B. Requirements for Injection Wells C. Spill Prevention, Control, and Countermeasure D. Shore Protection Act Regulations XIII. Summary of Public Participation XIV. Regulatory Implementation A. Toxicity Limitation for Drilling Fluids and Drill Cuttings B. Diesel Prohibition for Drilling Fluids and Drill Cuttings C. Upset and Bypass Provisions D. Variances and Modifications E. Synthetic Drilling Fluids F. Removal Credits for Indirect Dischargers G. Implementation for NPDES Permit Writers XV. Background Documents Appendix A to the Preamble--Abbreviations, Acronyms, and Other Terms Used in This Document I. Legal Authority This final regulation establishes effluent limitations guidelines and standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category under sections 301, 304, 306, 307, 308, and 501 of the Clean Water Act (CWA), 33 U.S.C. sections 1311, 1314, 1316, 1317, 1318, and 1361. The regulation is also being promulgated pursuant to a Consent Decree entered in NRDC et al. v. Reilly, (D D.C. No. 89- 2980, January 31, 1992) and is consistent with EPA's latest Effluent Guidelines Plan under section 304(m) of the CWA. (See 61 FR 52582, October 7, 1996). II. Purpose and Summary of This Rulemaking A. Purpose of This Rulemaking This final rule establishes effluent limitations guidelines and standards for the control of the discharge of pollutants for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category. The discharge limitations promulgated today apply to discharges from the coastal oil and gas industry. The processes and operations which comprise the coastal oil and gas subcategory (Standard Industrial Classification (SIC) Major Group 13) are currently regulated under 40 CFR part 435, subpart D. These regulations apply to those facilities engaged in field exploration, development drilling, production, and well treatment in the oil and gas industry that are in areas defined as ``coastal'' or that discharge into areas defined as ``coastal.'' The term ``coastal'' refers to a location in or on a water of the United States landward of the inner boundary of the territorial seas. In addition, any location in Texas or Louisiana between the Chapman Line and the inner boundary of the territorial seas is defined as ``coastal.'' The Chapman Line is defined by points of latitude and longitude within the states of Texas and Louisiana which are stated in the rule. The final rule promulgated today is referred to as the Coastal Guidelines throughout this preamble. This preamble highlights key aspects of the Coastal Guidelines. The technology descriptions and economic analyses discussed later in this notice are presented in abbreviated form. More detailed descriptions are included in the Development Document for Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category, referred to hereafter as the ``Coastal Development Document.'' EPA's economic impact assessment is presented in detail in the Economic Impact Analysis of Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category (hereinafter, ``EIA''), included in the rulemaking record. EPA's complete environmental benefits analysis is presented in the Water Quality Benefits Analysis of Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory [[Page 66088]] of the Oil and Gas Extraction Point Source Category (hereinafter, WQBA), included in the rulemaking record. B. Summary of the Final Coastal Guidelines This rule establishes regulations based on ``best practicable control technology currently available'' (BPT) for one wastestream where BPT did not previously exist, ``best conventional pollutant control technology'' (BCT), ``new source performance standards'' (NSPS), ``best available technology economically achievable'' (BAT), ``pretreatment standards for existing sources'' (PSES), and ``pretreatment standards for new sources'' (PSNS). Drilling fluids, drill cuttings, and dewatering effluent are limited under BCT, BAT, NSPS, PSES, and PSNS. BCT limitations are zero discharge, except for Cook Inlet, Alaska. In Cook Inlet, BCT limitations prohibit discharge of free oil. For both BAT and NSPS, EPA is establishing zero discharge limitations for drilling fluids, drill cuttings, and dewatering effluent except for Cook Inlet. In Cook Inlet, discharge limitations include no discharge of free oil, no discharge of diesel oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000 ppm SPP. For both PSES and PSNS, EPA is establishing zero discharge limitations in all coastal subcategory locations. Produced water and treatment, workover, and completion fluids are limited under BCT, BAT, NSPS, PSES, and PSNS. For BCT, EPA is establishing limitations on the concentration of oil and grease in produced water and treatment, workover, and completion fluids equal to current BPT limits. The Daily Maximum limitation for oil and grease is 72 mg/l and the Monthly Average limitation is 48 mg/l. For BAT and NSPS, EPA is establishing zero discharge limitations, except for Cook Inlet, Alaska. In Cook Inlet, the Daily Maximum limitation for oil and grease is 42 mg/l and the Monthly Average limitation is 29 mg/l. For both PSES and PSNS, EPA is establishing zero discharge limitations. For produced sand, EPA is establishing zero discharge limitations under BPT, BCT, BAT, NSPS, PSNS, and PSES. Deck drainage is limited under BCT, BAT, NSPS, PSES, and PSNS. For BCT, BAT, and NSPS, EPA is establishing discharge limitations of no free oil. For PSES and PSNS, EPA is establishing zero discharge limitations. Domestic waste is limited under BCT, BAT, and NSPS. For BCT, EPA is establishing no discharge of floating solids or garbage as limitations. For BAT, EPA is establishing no discharge of foam as the limitation. For NSPS, EPA is establishing no discharge of floating solids, foam, or garbage as limitations. There are no PSES and PSNS for domestic waste under the Coastal Guidelines. Sanitary waste is limited under BCT and NSPS. For BCT and NSPS, sanitary waste effluents from facilities continuously manned by ten or more persons would contain a minimum residual chlorine content of 1 mg/ l, with the chlorine level maintained as close to this concentration as possible. Facilities continuously manned by nine or fewer persons or only intermittently manned by any number of persons must not discharge floating solids. EPA is establishing no BAT, PSES, or PSNS regulations for sanitary waste under the Coastal Guidelines. III. Background The objective of the Clean Water Act is to ``restore and maintain the chemical, physical, and biological integrity of the Nation's waters''. To that end, it is the national goal that the discharge of pollutants to the nations waters be eliminated. CWA section 101. A. Definitions of Guidelines and Standards To assist in achieving the objective of the CWA, EPA issues effluent limitations guidelines, pretreatment standards, and new source performance standards for industrial dischargers. These guidelines and standards are summarized below: 1. Best Practicable Control Technology Currently Available (BPT)--Sec. 304(b)(1) of the CWA BPT effluent limitations guidelines apply to discharges of conventional, toxic, and nonconventional pollutants from existing sources. BPT guidelines are generally based on the average of the best existing performance by plants in a category or subcategory. In establishing BPT, EPA considers the cost of achieving effluent reductions in relation to the effluent reduction benefits, the age of equipment and facilities, the processes employed, process changes required, engineering aspects of the control technologies, non-water quality environmental impacts (including energy requirements), and other factors as the Administrator deems appropriate. CWA section 304(b)(1)(B). Where existing performance is uniformly inadequate, BPT may be transferred from a different subcategory or category. 2. Best Conventional Pollutant Control Technology (BCT)--Sec. 304(b)(4) of the CWA The 1977 amendments to the CWA established BCT as an additional level of control for discharges of conventional pollutants from existing industrial point sources. In addition to other factors specified in section 304(b)(4)(B), the CWA requires that BCT limitations be established in light of a two part ``cost- reasonableness'' test. EPA published a methodology for the development of BCT limitations which became effective August 22, 1986 (51 FR 24974, July 9, 1986). Section 304(a)(4) designates the following as conventional pollutants: biochemical oxygen demanding pollutants (measured as BOD5), total suspended solids (TSS), fecal coliform, pH, and any additional pollutants defined by the Administrator as conventional. The Administrator designated oil and grease as an additional conventional pollutant on July 30, 1979 (44 FR 44501). 3. Best Available Technology Economically Achievable (BAT)--Sec. 304(b)(2) of the CWA In general, BAT effluent limitations guidelines represent the best existing economically achievable performance of facilities in the industrial subcategory or category. The CWA establishes BAT as a principal national means of controlling the direct discharge of toxic and nonconventional pollutants. The factors considered in assessing BAT include the age of equipment and facilities involved, the process employed, potential process changes, non-water quality environmental impacts, including energy requirements, and such factors as the Administrator deems appropriate. The Agency retains considerable discretion in assigning the weight to be accorded these factors. An additional statutory factor considered in setting BAT is economic achievability across the subcategory. Generally, the achievability is determined on the basis of total costs to the industrial subcategory and their effect on the overall industry financial health. As with BPT, BAT may be transferred from a different subcategory or category. BAT may be based upon process changes or internal controls, even when these technologies are not common industry practice. 4. Best Available Demonstrated Control Technology For New Sources (BADCT)--Sec. 306 of the CWA NSPS are based on the best available demonstrated treatment technology and [[Page 66089]] apply to all pollutants (conventional, nonconventional, and toxic). New facilities have the opportunity to install the best and most efficient production processes and wastewater treatment technologies. Under NSPS, EPA is to consider the best demonstrated process changes, in-plant controls, and end-of-process control and treatment technologies that reduce pollution to the maximum extent feasible. In establishing NSPS, EPA is directed to take into consideration the cost of achieving the effluent reduction and any non-water quality environmental impacts and energy requirements. 5. Pretreatment Standards for Existing Sources (PSES)--Sec. 307(b) of the CWA PSES are designed to prevent the discharge of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of publicly-owned treatment works (POTW). The CWA authorizes EPA to establish pretreatment standards for pollutants that pass through POTWs or interfere with treatment processes or sludge disposal methods at POTWs. Pretreatment standards are technology-based and analogous to BAT effluent limitations guidelines. The General Pretreatment Regulations, which set forth the framework for the implementation of categorical pretreatment standards, are found at 40 CFR part 403. Those regulations contain a definition of pass- through that addresses localized rather than national instances of pass-through and establish pretreatment standards that apply to all non-domestic dischargers. See 52 FR 1586, January 14, 1987. 6. Pretreatment Standards for New Sources (PSNS)--Sec. 307(b) of the CWA Like PSES, PSNS are designed to prevent the discharges of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of POTWs. PSNS are to be issued at the same time as NSPS. New indirect dischargers have the opportunity to incorporate into their facilities the best available demonstrated technologies. EPA considers the same factors in promulgating PSNS as it considers in promulgating NSPS. B. Requirements for Promulgating, Reviewing, and Revising Guidelines and Standards Section 304(m) of the CWA requires EPA to establish schedules for (i) reviewing and revising existing effluent limitations guidelines and standards and (ii) promulgating new effluent guidelines. On January 2, 1990, EPA published an Effluent Guidelines Plan (55 FR 80), in which schedules were established for developing new and revised guidelines for several industry categories, including the coastal oil and gas industry. Natural Resources Defense Council, Inc., challenged the Effluent Guidelines Plan in a suit filed in the U.S. District Court for the District of Columbia, (NRDC et al. v. Reilly, Civ. No. 89-2980). On January 31, 1992, the Court entered a consent decree (the ``304(m) Decree''), which establishes schedules for, among other things, EPA's proposal and promulgation of effluent guidelines for a number of point source categories, including the Coastal Oil and Gas Industry. The most recent proposed Effluent Guidelines Plan was published in the Federal Register on October 7, 1996 (61 FR 52582). C. History of the Rulemaking EPA promulgated BPT effluent limitations guidelines for all subcategories under the oil and gas point source category on April 13, 1979 (44 FR 22069). Since then, EPA published a notice of information and request for comments on the coastal subcategory on November 8, 1989 (54 FR 46919) and published the proposed Coastal Guidelines on February 17, 1995 (60 FR 9428). IV. Description of the Industry Coastal oil and gas activities include field exploration, drilling, production, and well treatment. Coastal activities are located on waters of the United States inland of the inner boundary of the territorial seas. These water bodies include inland lakes, bays and sounds, as well as saline, brackish, and freshwater wetland areas. Although the definition includes waters of the U.S. even in all inland states, EPA knows of no existing operations other than those in certain states bordering the coast. The definition also includes certain wells in Texas and Louisiana between the ``Chapman Line'' and the inner boundary of the territorial seas as coastal. Thus, at this time, the coastal oil and gas operations are located only in coastal states. Table 1 summarizes the number of producing wells and annual drilling activities for the coastal subcategory. Table 1.--Profile of Coastal Oil and Gas Industry ---------------------------------------------------------------------------------------------------------------- Number of Number of Coastal location Region producing wells production Annual drilling (1992) facilities (1992) activity (wells) ---------------------------------------------------------------------------------------------------------------- Gulf of Mexico............... Texas and Louisiana.. 4675 853 686 Alabama and Florida.. 56 \1\ ND 7 Alaska....................... Cook Inlet........... 237 8 9 North Slope.......... 2085 12 161 California................... Long Beach Harbor.... 586 4 7 ----------------------------------------------------------- Total.................... ..................... 7639 877 870 ---------------------------------------------------------------------------------------------------------------- \1\ Not determined. The primary wastewater sources from the exploration and development phases of the coastal oil and gas extraction industry include the following: Drilling fluids Drill cuttings Sanitary wastes Deck drainage Domestic wastes The primary wastewater sources from the production phase of the industry include the following: Produced water Produced sand Well treatment, workover, and completion fluids Deck drainage Domestic wastes Sanitary wastes Drilling fluids and drill cuttings are the most significant waste streams from exploratory and development operations in terms of volume and pollutants. Produced water is the largest waste stream from production activities in terms of volumes discharged and quantity of pollutants. Discharges from coastal oil and gas operations in states along the Gulf of [[Page 66090]] Mexico, California, and Alaska are regulated by general and individual NPDES permits based on BPT, State Water Quality Standards, and on Best Professional Judgment (BPJ) of BCT and BAT levels of control. A more detailed description of the industry is included in the Coastal Development Document, contained in the record for this rule. V. Major Changes to the Database for the Final Regulation This section describes several of the most significant changes which have occurred since proposal to the methodology and data base used to calculate compliance costs, pollutant reductions, and non-water quality environmental impacts. Other changes and issues are discussed in other sections of the preamble, the Development Document, the Economic Impact Analysis, the environmental benefits analysis documents, and the record for this rule. A. Drilling Fluids and Drill Cuttings The compliance costs and pollutant removals presented in the Development Document for the proposed rule have been revised to reflect information received from coastal industry operators in response to the proposal. As in the analysis for the proposal, drilling waste compliance cost and pollutant reductions calculations apply only to operations in Cook Inlet, Alaska because the rest of the coastal subcategory is already attaining zero discharge. Since proposal, the industry profile in Cook Inlet has changed, increasing the total waste volume on which costs and removals are based by about 15 percent. In addition, industry-supplied information resulted in changes to particular cost items within the zero discharge analysis. 1. Drilling Projections EPA's profile of future drilling activity in Cook Inlet is based on information submitted by Cook Inlet operators. In the Development Document for the proposal, EPA identified one operator in the analysis which had recently canceled plans to drill six new wells. This information about the cancellation was received too late to allow for revision of the analysis prior to proposal. EPA has since proposal confirmed that the operator does not intend to drill these wells and they are not included in the revised cost and pollutant reductions analyses for the final rule. EPA received other information in comments on the proposal updating the drilling plans for other operators in Cook Inlet. Compared to the profile used for the proposal, the total number of new wells at existing platforms anticipated during the seven years following promulgation increased by four and the total number of platforms with drilling schedules decreased by two. 2. Engineering Costs As was done for the proposal, EPA evaluated two disposal technologies for complying with a zero discharge limitation for drilling fluids and drill cuttings: 1) transport to shore for land disposal; and 2) grinding of the drilling wastes followed by injection in a dedicated disposal well. At proposal, compliance costs were based on an assumption that both land disposal and downhole injection were available technologies for all drilling locations in Cook Inlet. Costs for both compliance technologies were developed for each operator and the lowest cost compliance scenario was selected as the likely cost of the proposed rule. As a result, costs for two operators were based on disposal by injection. In response to comments disputing the feasibility of injecting drilling wastes into the geologic formations present in Cook Inlet, EPA reviewed information in the record and sought additional information on this issue from industry and State and Federal authorities. Based on the limited data available to date, EPA believes that the information in the record indicates that certain sites in Cook Inlet may not be able to inject sufficient volumes of drilling wastes to enable compliance with zero discharge as EPA has defined the technology. See the Development Document and section VII of the preamble for additional information. For the final rule, EPA has based zero discharge compliance costs for all operators on disposal of the drilling wastes at landfills. This is because EPA is unable at this time, with the limited data available, to estimate the degree to which injection would be available in Cook Inlet. The costing methodologies for the landfill and injection scenarios in the final rule are based, in general, on the costing methodologies presented in the proposal. However, EPA improved the database and sought additional confirmatory data in response to comments on the proposal. Engineering costs have been adjusted from 1992 dollars to 1995 dollars to better reflect the current cost of compliance with zero discharge. Certain changes resulting from EPA's reevaluation of costing assumptions have led to a revision in the cost of landfilling drilling wastes. In response to comments, EPA reevaluated certain assumptions related to the use of supply boats and barges in transporting drilling wastes to shore for disposal at landfills. These comments led to a reassessment of platform storage space and boat capacities and resulted in an increase in the number of boat trips required to haul the drilling wastes. As discussed at proposal, the sole land disposal site for drilling wastes in Cook Inlet (referred herein as the Kustatan landfill) is a private facility owned by two of the operators. While no regulatory obstacles would prohibit disposing of the wastes from other operators at the Kustatan landfill, since it is a private facility its availability for use by third parties cannot be assured. As a result, EPA's analysis considers the Kustatan landfill to be available for use by only two of the operators in the region. Since no other land disposal facilities in Alaska are believed available to the remaining Cook Inlet operators, the analysis for the proposal based land disposal costs for these operators on transporting the drilling wastes to a disposal facility in Idaho. In the preamble for the proposed rule, EPA discussed the availability of another disposal facility located in Oregon and stated that costs using this facility were expected to be ``close to or less than the costs of using the Idaho facility.'' (See 60 FR 9442) Further review of these facilities has shown that savings would in fact be realized using the Oregon facility and it is the disposal site used in the final cost analysis. EPA also revised costing estimates to address industry comments regarding specific fees associated with disposal at the Kustatan landfill. B. Produced Water 1. Industry Profile a. Gulf of Mexico. For the analyses performed for the proposed rule, EPA used information provided by industry sources and state regulatory authorities to construct a profile of production facilities currently discharging in coastal areas of the Gulf of Mexico. Under regulations issued by the State of Louisiana, many facilities are required to cease discharges of produced water. Based on the data available to EPA at proposal, EPA estimated that there would be 216 production facilities discharging in the Gulf of Mexico by July 1996 (the original date scheduled for promulgating final Coastal Guidelines). Shortly before the proposal was published, EPA's Region 6 published final NPDES General Permits regulating produced water and produced sand discharges to coastal waters in Louisiana and Texas (60 FR [[Page 66091]] 2387; January 9, 1995). These permits prohibited the discharge of any produced water derived from coastal waters of Louisiana and Texas. Because much of the industry covered by the proposed Coastal Guidelines is also covered by these General Permits, the industry profile used in the cost and economic analyses for the proposed rule overstates the number of facilities that would be incrementally affected by the final Coastal Guidelines. This discrepancy was noted at proposal. In the preamble for the proposed Coastal Guidelines, EPA stated that due to the close proximity (one month) of the timing of the publication of the Region 6 General Permits and the proposed guidelines, the costs and impacts of the proposed Coastal Guidelines was being presented in the preamble as if the General Permits were not final. EPA presented preliminary results of how the costs and impacts of the Coastal Guidelines would be reduced when the General Permits became effective and stated that the regulatory effects of the General Permits would be incorporated in the analysis conducted for the final guidelines. See 60 FR 9430. The main difference between the general permits and the Coastal Guidelines is that the permits cover wastes generated by onshore Stripper Subcategory wells that are not covered under the Coastal Guidelines and the Louisiana permit does not cover produced water derived from Offshore Subcategory wells that is discharged into a major deltaic pass of the Mississippi River, or to the Atchafalaya River below Morgan City including Wax Lake Outlet. Since proposal, EPA has worked with industry sources and State regulatory authorities to identify those facilities whose discharges are covered by the Coastal Guidelines, but are not covered by General Permits. No facilities discharging Offshore Subcategory produced water into the Atchafalaya River were identified. Six production facilities with a total of eight outfalls were identified as discharging produced water derived from Offshore Subcategory wells into the major deltaic passes of the Mississippi River. As discussed in the Supplementary Information section of this preamble, subsequent to the issuance of the general permits requiring zero discharge in the Gulf of Mexico region, EPA received individual permit applications from Texas dischargers seeking to discharge produced water. Additionally, the U.S. Department of Energy (DOE) has provided the State of Louisiana with comments and analyses suggesting a change in the Louisiana state law requiring zero discharge of produced water to open bays by January 1997. Because promulgation of this rule requiring zero discharge in these areas would preclude issuance of permits allowing discharge, EPA also calculated an alternative estimate of the costs, economic impacts, and pollutant removals under an ``alternative baseline.'' This ``alternative baseline'' assumes that zero discharge under the general permits would no longer apply to Texas dischargers seeking individual permits and Louisiana open bay dischargers. To do this, EPA reviewed the list of facilities requesting an individual permit in Texas, 82 as of the date of this writing, and identified the number of facilities discharging to open bays using information developed by the State of Louisiana for the DOE study of open bays. EPA obtained all available information about these facilities from the states and EPA's Coastal Questionnaire and used this information to develop estimates of the technological availability, costs and economic achievability, non-water quality environmental impacts, and pollutant removals achieved by zero discharge. b. Cook Inlet. EPA updated the profile of Cook Inlet production facilities with current hydrocarbon and water production rates to address information submitted by industry in comments. The profile was also updated with current waterflood rates for use in estimating compliance costs under the produced water zero discharge option. The most notable changes to the Cook Inlet production profile include one platform which resumed oil production and ceased waterflooding; two platforms that resumed waterflooding; and one platform substantially reduced its waterflood rate. Production and waterflood levels for the remaining Cook Inlet facilities have not changed significantly since 1993. These profile changes are discussed in detail in the Development Document and the record for the final rule. 2. Engineering Costs a. Gulf of Mexico. Engineering costs have been adjusted from 1992 dollars to 1995 dollars to better reflect the current cost of compliance with zero discharge. Other than the adjustment to 1995 dollars, no significant changes were made to compliance cost estimates for the improved gas flotation option. The more significant changes to the cost estimates for the zero discharge option are discussed below. Total labor costs in the final analysis are nearly double the labor costs estimated at proposal. The labor burden associated with operating additional BAT/NSPS control technologies is unchanged from the analysis for the proposed rule, but the labor rate has been revised upward based on data from Bureau of Labor Statistics. Additional O&M costs were added to reflect the costs of replacing the filter cartridges used to remove solids from the produced water prior to injection. O&M costs for injection pretreatment chemicals were revised based on new data provided by the industry, in combination with the data used at proposal. Chemicals are already added to the produced water at treatment facilities and source water in waterflooding operations at existing production locations. The treatment chemical costs included in EPA's analysis are costs added incremental to current chemical expenditures. In response to comments about the potential for solids buildup causing downhole problems in injection wells, EPA reviewed the workover data in the record. For the final rule, the frequency of backwashing injection wells was doubled--from biennial to once annually. Pipeline costs have also been increased since proposal. While reviewing comments regarding pipeline costs, EPA detected a scale up error in the proposal analysis which led to underestimating costs. In estimating costs, EPA also took into account facility-specific data and comments where it showed discharges were currently capable of meeting limits based on operation of improved gas flotation. b. Cook Inlet. Other than to adjust costs to 1995 dollars, no significant changes were made to Cook Inlet compliance cost estimates for the limitations based on gas flotation. As at proposal, compliance with zero discharge for the Cook inlet facilities is based on the injection of produced water into production zones as part of the ongoing waterflood operations or into dedicated disposal wells where waterflooding operations do not exist. In response to concerns raised in industry comments, capital costs for installation of a centrifuge to dewater filtration backwash solids were added to platforms assumed to inject produced water under the zero discharge scenario. Centrifuges would be used to concentrate the solids removed from the filtered produced water, thus allowing the liquid portion of the backwash to be injected. The dewatered solids would then be disposed of by transport to a landfill (as costed by EPA) or injected into a disposal well. This disposal cost [[Page 66092]] is included as a new O&M cost in the analysis for the final Coastal Guidelines. O&M costs for treatment chemicals (e.g., scale inhibitors, corrosion inhibitors, biocides) were revised based on industry data. All locations that treat produced water prior to injection under the zero discharge scenario are assumed to incur costs for treatment chemicals. It should be noted that all facilities currently treating produced water for discharge already add some chemicals to enhance separation and provide protection of treatment equipment. Further, all facilities currently waterflooding seawater also add treatment chemicals prior to injection. The treatment chemical costs included in EPA's estimated compliance costs are incremental to current treatment facility and waterflooding chemical expenditures and therefore are considered to adequately address industry concerns about chemical addition costs resulting from injecting produced water into producing formations. Information in the record indicates that injection well workover costs were underestimated at proposal. Workover costs for the final analysis were increased based on comments from Cook Inlet operators and a comparison to cost data for workovers in the Gulf of Mexico. 3. Pollutant Reduction Estimates Similar to the February 1995 proposal, pollutant removals for the different produced water regulatory options of the final rule were determined by comparing the estimated effluent levels of pollutants after treatment by the BAT/NSPS treatment system (improved performance of gas flotation or reinjection) versus the effluent levels of pollutants associated with a typical BPT treatment (gravity separation or gas flotation). In the proposal, EPA characterized BPT treatment in the Gulf of Mexico using data collected from ten coastal oil and gas facilities located in Louisiana and Texas. Comments received subsequent to the proposal stated that the facilities included in the database do not adequately represent the quality of produced water which has undergone BPT-level treatment and, as a result, overestimate the pollutant reductions associated with the BAT/NSPS control options. Several comments also disputed the presence of certain pollutants included in EPA's BPT characterization. In response to these comments, EPA reassessed the characterization of BPT-level effluent quality. Certain pollutants were dropped for the final analysis because they are believed to have been measured as a result of laboratory contamination or are otherwise not expected to be present in produced water. In comparison to the total mass of pollutants removed by the technologies evaluated in the BAT/NSPS options, excluding these pollutants had negligible effect on the reductions estimates. The pollutants excluded from the final analysis and the reasons for the exclusion are discussed in the Development Document, the Response to Comments Document, and the record. Upon review of the data used at proposal, EPA determined that three of the facilities making up the Ten Facility dataset should be excluded from the BPT characterization for the final rule. These facilities had high levels of oil and grease, in excess of that allowed to be discharged under the BPT effluent limitations guidelines, and therefore the pollutant levels at these facilities are not considered representative of produced water which has been treated to a level which would allow discharge to surface waters. (Produced water from these facilities is disposed of through downhole injection.) EPA believes it is appropriate to continue using the effluent data collected from the remaining seven facilities to represent BPT-level pollutant concentrations, even though not all of these facilities actually discharge their produced water, since the treatment technology at these facilities is typical of that used at the majority of coastal facilities and the oil and grease content of the effluent for these facilities was lower than that required to meet the existing BPT effluent limitations. Total oil and grease measurements at these seven facilities range from 8 mg/l to 43 mg/l. When averaged together, the average oil and grease concentration for the seven facilities is 26.6 mg/l, in contrast to an average of 53 mg/l when using data from all ten facilities. EPA notes that this revised calculation of the oil and grease concentration in BPT-level effluent for the coastal subcategory (26.6 mg/l) compares favorably to the BPT-level effluent data (25 mg/l) collected previously for the offshore subcategory. (See Section IX of the Development Document for Effluent Limitations Guidelines and Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category, EPA 821-R-93-003, January 1993.) The technology basis used to develop BPT limitations for the coastal subcategory is identical to the basis used to develop the offshore subcategory BPT limitations. (See the Development Document for Interim Final Effluent Limitations Guidelines and Proposed New Source Performance Standards for the Oil and Gas Extraction Point Source Category, EPA 440/1-76/ 055a, September 1976.) EPA also took into account facility-specific data and comments where it showed discharges were currently capable of meeting limits based on operation of improved gas flotation in assessing pollutant reductions estimates. VI. Summary of the Most Significant Regulatory Changes From Proposal This section briefly identifies the most significant changes from proposal. More detailed discussion of these changes, and identification and discussion of other issues are included in other sections of this notice, the Coastal Development Document, the Economic Impact Analysis, and the record for this rule. The most significant changes from proposal occurred with regards to: (1) Drilling fluids, drill cuttings, and dewatering effluent and (2) produced water and treatment, workover, and completion fluids. For drilling fluids, drill cuttings, and dewatering effluent, EPA proposed three options for both BAT and NSPS limitations. The three options were: (1) Zero discharge of drilling fluids, drill cuttings, and dewatering effluent except for Cook Inlet, where discharge limitations include no discharge of free oil, no discharge of diesel oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000 ppm SPP; (2) Zero discharge of drilling fluids, drill cuttings, and dewatering effluent except for Cook Inlet, where discharge limitations include no discharge of free oil, no discharge of diesel oil, both 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation more stringent than 30,000 ppm SPP; and (3) Zero discharge everywhere. For both BAT and NSPS, option (1) has been selected for the final rule. For produced water and treatment, workover, and completion fluids, EPA proposed zero discharge everywhere for NSPS. For the final rule, NSPS limitations are zero discharge except for Cook Inlet, Alaska. In Cook Inlet, the Daily Maximum limitation for oil and grease is 42 mg/l and the Monthly Average limitation is 29 mg/l. [[Page 66093]] VII. Basis for the Final Regulation A. Drilling Fluids, Drill Cuttings, and Dewatering Effluent 1. Waste Characterization Drilling fluids and drill cuttings are typically discharged in bulk during episodes that occur intermittently during well drilling and at the end of the drilling phase. There are currently no drilling fluid or drill cuttings discharges in any coastal area except for Alaska's Cook Inlet. Zero discharge is generally met by a combination of landfilling and injection. On Alaska's North Slope, while all drilling fluids and most drill cuttings are injected, some cuttings are cleaned and used as fill material in the construction of drill pads and roads. These fill materials require a fill permit issued pursuant to section 404 of the CWA. In Cook Inlet, operators do not currently practice zero discharge, except for a small volume of drilling fluids and cuttings wastes (approximately one percent) which are not discharged because they do not meet current permit limits. Generally, drilling fluids and cuttings volumes average approximately 14,000 barrels (bbl) per new well drilled in Cook Inlet. (NOTE: The barrel is a standard oil and gas measurement and is equal in volume to 42 gallons). Based on industry projections given to EPA, an average of 89,000 bbls drilling fluids and cuttings are generated each year (bpy) in the Inlet. Pollutants present in these wastes include chromium, copper, lead, nickel, selenium, silver, beryllium and arsenic among the toxic metals. Toxic organics present include naphthalene, fluorene, and phenanthrene. Total Suspended Solids (TSS) make up the bulk of the pollutant loadings, part of which is comprised of the above mentioned toxic pollutants. TSS concentrations are very high due to the nature of the wastes. Operators use solids control equipment to remove drill cuttings from the drilling fluid systems which allows drilling fluids to be recycled and reduces the total amount of drilling wastes generated. Depending on the solids control system and the method of waste storage and disposal onsite, a small wastestream, termed ``dewatering effluent'' may be segregated from the drilling fluids and cuttings. Dewatering effluent may be discharged from reserve pits or tanks which store drilling wastes for reuse or disposal. Dewatering effluent may also be generated in enhanced solids control systems. Enhanced solids control systems, also known as closed-loop solids control operations, remove solids from the drilling fluid at greater efficiencies than conventional solids removal systems. Increased solids removal efficiency minimizes the buildup of drilled solids in the drilling fluid system, and allows a greater percentage of drilling fluid to be recycled. Smaller volumes of new or freshly made fluids are required as a result. An added benefit of the closed-loop technology is that the amount of waste drilling fluids can be significantly reduced. The installation of reserve pits is unnecessary in closed-loop systems for this reason. EPA's general permits for drilling operations in Texas and Louisiana (58 FR 49126, September 21, 1993) have limitations for the discharge of dewatering effluent, while other parts of the nation generally treat dewatering effluent as part of the drilling fluids wastestream. However, results from the 1993 Coastal Oil and Gas Questionnaire show that few operators discharge dewatering effluent as a separate wastestream. Additionally, contacts with industry indicate that the volume of dewatering effluent from reserve pits is small and growing smaller since the use of pits is phasing out due to state permit conditions, environmental or land owner concern, and the expanding use of closed-loop systems. EPA site visits to drilling operations, where these closed-loop systems were in place, showed that none of the dewatering effluent is discharged. Instead, it is either recycled, or sent with other drilling wastes to commercial disposal. Operators at these facilities explained that it is less expensive to send this wastestream along with drilling fluids and drill cuttings for onshore disposal rather than to treat for discharge. 2. Selection of Pollutant Parameters a. Pollutants Regulated. EPA is establishing BAT, BCT, NSPS, PSES, and PSNS limitations that would require zero discharge of drilling fluids, drill cuttings, and dewatering effluent, except for BAT, BCT, and NSPS in Cook Inlet, Alaska. Where zero discharge is required, EPA would be controlling all pollutants in the wastestream. For BAT and NSPS in Cook Inlet, discharge limitations for drilling fluids, drill cuttings, and dewatering effluent include no discharge of free oil, no discharge of diesel oil, 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000 ppm SPP. As presented in the Coastal Development Document, the prohibitions on the discharge of free oil and diesel oil would effectively remove toxic, nonconventional, and conventional pollutants. Diesel oil and free oil are considered, under BAT and NSPS, to be ``indicators'' for the control of specific toxic pollutants present in the complex hydrocarbon mixtures used in drilling fluid systems. Free oil is also an indicator for toxic pollutants present in crude oil. These pollutants include benzene, toluene, ethylbenzene, naphthalene, phenanthrene, and phenol. Additionally, diesel oil may contain from 20 to 60 percent by volume polynuclear aromatic hydrocarbons (PAHs) which constitute the more toxic components of petroleum products. Control of diesel oil would also result in the control of nonconventional pollutants under BAT and NSPS. Diesel oil contains a number of nonconventional pollutants, including PAHs such as methylnaphthalene, methylphenanthrene, and other alkylated forms of the listed organic toxic pollutants. EPA is establishing BCT limitations for drilling fluids, drill cuttings, and dewatering effluent that prohibit the discharge of free oil (using the static sheen test) for Cook Inlet. The prohibition on the discharge of free oil would effectively reduce or eliminate the oil and grease in these discharges. EPA is limiting free oil under BCT as a surrogate for oil and grease in recognition of the complex nature of the oils present in drilling fluids, including crude oil from the formation being drilled. For Cook Inlet, prohibiting the discharge of diesel oil and free oil eliminates discharges of the above listed constituents, to the extent that these constituents are present in either of these two parameters, and reduces the level of oil and grease present in the discharged drilling fluids and cuttings. Also, limitations on cadmium and mercury content in barite will control toxic and nonconventional pollutants in drilling waste discharges. This limitation directly controls the levels of cadmium and mercury, and indirectly controls the levels of other toxic pollutant metals. Control of other toxic pollutant metals occurs because cleaner barite that meets the mercury and cadmium limits has been shown to have reduced concentrations of other metals. Evaluation of the relationship between cadmium and mercury and the trace metals in barite shows a correlation between the concentration of mercury with the concentration of arsenic, chromium, copper, lead, molybdenum, sodium, tin, titanium and zinc; and the concentration of cadmium with the concentration of arsenic, boron, calcium, sodium, tin, titanium, and [[Page 66094]] zinc. (See the Coastal Development Document). Toxicity of drilling fluids, drill cuttings, and dewatering effluent is being regulated as a nonconventional pollutant that controls certain toxic and nonconventional pollutants. It was shown, during EPA's development of the Offshore Guidelines, that control of toxicity encourages the use of less toxic, water-based drilling fluids, and where absolutely necessary, the use of less mineral oil added to a drilling fluid (and the pollutants, such as the PAH's, identified as constituents of mineral oil). A toxicity limitation thus encourages the use of low-toxicity drilling fluids and the use of low-toxicity drilling fluid additives. b. Pollutants Not Regulated. Where zero discharge is required, all pollutants are controlled. In Cook Inlet, EPA has determined that it is not technically feasible to specifically control each of the toxic constituents of drilling fluids and cuttings that are controlled by the limits on the pollutants established in this regulation. EPA has determined that certain of the toxic and nonconventional pollutants are not controlled by the limitations on diesel oil, free oil, toxicity, and mercury and cadmium in stock barite. EPA exercised its discretion not to regulate these pollutants because EPA did not detect these pollutants in more than a very few of the samples from EPA's field sampling program and does not believe them to be found throughout the industry; the pollutants when found are present in trace amounts not likely to cause toxic effects; and due to the large number and variation in additives or specialty chemicals that are only used intermittently and at a variety of drilling locations, it is not feasible to set limitations on specific compounds contained in additives or specialty chemicals. See the Coastal Development Document for further discussion. 3. Control and Treatment Technologies a. Current Practice. BPT effluent limitations guidelines for coastal drilling fluids and drill cuttings prohibit the discharge of free oil (using the visual sheen test). However, because of either EPA general and individual permits, state requirements, or operational preference, no drilling fluids and cuttings discharges are occurring in the coastal waters of the Gulf coast states or California. The only coastal operators disposing of drilling fluids and drill cuttings by discharge are located in Cook Inlet. In Cook Inlet, neither diesel nor mineral-oil-based drilling fluids or resultant cuttings may be discharged to surface waters. Compliance with the BPT limitations may be achieved either by product substitution (substituting a water-based fluid for an oil-based fluid), recycle and/or reuse of the drilling fluid, onshore disposal of the drilling fluids and cuttings at an approved facility, or disposal by injection where feasible. On Alaska's North Slope, all drilling fluids and most drill cuttings are injected, though some cuttings are cleaned for use as fill material for the construction of drilling pads and roads. This fill activity is regulated under section 404 of the CWA. NPDES permits issued by EPA for Cook Inlet drilling operations have also included BAT limitations based on ``best professional judgement'' (BPJ). The permit requirements allow discharges of drilling fluids and drill cuttings provided certain limitations are met including a prohibition on the discharges of free oil and diesel oil, as well as limitations on mercury, cadmium, toxicity and oil content. Operators in Cook Inlet typically employ the following waste management practices to meet those permit limitations: * Product substitution--to meet prohibitions on free oil and diesel oil discharges, as well as the toxicity and/or clean barite limitations, * Onshore treatment and/or disposal of drilling fluids and drill cuttings that do not meet the toxicity limitations, * Waste minimization--enhanced solids control to reduce the overall volume of drilling fluids and drill cuttings, and * Conservation and recycling/reuse of drilling fluids. Refer to the Coastal Development Document for a detailed discussion of each of these waste management techniques. b. Additional Technologies Considered. EPA has evaluated an additional method for drilling fluid, drill cuttings, and dewatering effluent control and treatment in order to achieve zero discharge: namely, grinding and injection of drilling wastes. This process involves the grinding of the drilling fluids, drill cuttings, and dewatering effluent into a slurry that can be injected into a dedicated disposal well. The grinding system consists of a vibrating or rotating ball mill which pulverizes the cuttings and creates an injectable slurry. This comparatively contemporary technology has been successfully demonstrated on the North Slope, and has been used to a limited degree on the Gulf Coast. While injection has been demonstrated in other parts of the U.S., injection has not been demonstrated in Cook Inlet. EPA believes that the ability to inject is related to the subsurface conditions of the receiving formations. While the geology of the formations in areas other than Cook Inlet have been favorable to injection of drilling fluids and drill cuttings, the record indicates that geology amenable to grinding and injection does not appear to occur throughout Cook Inlet. In addition to grinding and injection, EPA has investigated the feasibility of onshore disposal for this wastestream. For the coastal subcategory drilling activities, in areas other than Cook Inlet, current permits require zero discharge of drilling fluids and cuttings or, in the case of the North Slope, zero discharge of drilling fluids, and drill cuttings except where drill cuttings are reused as a fill material. The fill activity is regulated under section 404 of the CWA. On-land disposal or downhole injection sites are available in these areas and are being utilized to comply with the zero discharge requirement. With respect to onshore disposal capacity, on-land disposal sites are available to two of the Cook Inlet operators. These two operators jointly own an oil and gas landfill disposal site on the west side of the Inlet. Unfortunately, no on-land oil and gas waste disposal facilities are available in Alaska to the other Cook Inlet operators who plan to drill after promulgation of this rule. Therefore, EPA has estimated the costs for disposing of drilling wastes at an on-land oil and gas waste disposal site in Oregon. Also with regard to zero discharge, EPA received information from operators concerned that compliance with zero discharge could significantly interfere with drilling operations. EPA has investigated the significant logistical difficulties and operational problems presented by storing and transporting drilling wastes in the Cook Inlet, due to the space constraints, combined with the extensive tidal fluctuations, strong currents, and ice formation during winter months. Also, EPA has taken into consideration supplementary costs incurred by additional winter transportation and storage of drilling wastes in its cost evaluation of the zero discharge option as described below. In addition to zero discharge, EPA considered allowing the discharge of the drilling fluids, drill cuttings, and dewatering effluent in Cook Inlet providing the discharge met certain limitations. These limitations would prohibit the discharge of diesel oil and free oil using the static sheen test, limit cadmium and mercury in the stock barite used in fluid compositions, and [[Page 66095]] limit toxicity at either 30,000 ppm (SPP) or a more stringent toxicity in range of 100,000 ppm (SPP) to 1 million ppm (SPP). (The measure of toxicity is a 96 hour test that estimates the concentration of suspended particulate phase (SPP) from a drilling fluid that is lethal to 50 percent of the tested organisms. See 40 CFR part 435, subpart A, appendix 2). Drilling fluids and drill cuttings not meeting these limitations would not be allowed to be discharged, and therefore, would have to be injected or sent to shore for disposal. As discussed above, one option at proposal would have retained the offshore limitations but required a more stringent toxicity limit. At proposal, EPA based the more stringent toxicity limitations, in part, on the volume of drilling wastes that could be injected or disposed of onshore without interfering with ongoing drilling operations. The more stringent toxicity limit would have been based on (1) the volume of drilling wastes that could be subjected to zero discharge without interfering with ongoing drilling operations and (2) a specified level of toxicity selected such that no more than this volume of waste, determined in the previous step, would exceed the specified level of toxicity. However, as pointed out in comments on the proposal and confirmed with further investigation, there are a number of problems with the database that would be used to establish a more stringent toxicity limitation. Many of the records in the database do not have either a waste volume identified or indicate whether the drilling fluids were discharged. Where waste volumes are reported, the methods used to determine these volumes are not consistent and they are not documented. It is also unclear whether the volumes and fluid systems reported for any given well represent a complete record of the drilling activity associated with the well. For these reasons, EPA rejected the option of developing a more stringent toxicity limitation for the final rule. 4. BAT and NSPS Options For final consideration, EPA developed two options for the BAT and NSPS level of control for drilling fluids and drill cuttings. Limitations for the dewatering effluent are the same as those for drilling fluids and drill cuttings. Option 1 would require zero discharge of drilling fluids, drill cuttings, and dewatering effluent for all coastal drilling operations except those located in Cook Inlet. Allowable discharge limitations for drilling fluids and cuttings in Cook Inlet would require compliance with a toxicity value of no less than 30,000 ppm (SPP); no discharge of free oil (as determined by the static sheen test); no discharge of diesel oil and 1 mg/kg of mercury and 3 mg/kg of cadmium in the stock barite. Limitations for Cook Inlet are identical to the limitations applicable to offshore discharges in Alaska. Option 1 was developed taking into consideration that Cook Inlet operations are unique to the industry due to a combination of geology available for grinding and injection, climate, transportation logistics, and structural and space limitations that interfere with drilling operations. Option 2 would prohibit the discharge of drilling fluids, drill cuttings, and dewatering effluent from all coastal oil and gas drilling operations. In Cook Inlet, this option uses onshore disposal as a basis for complying with zero discharge of drilling fluids and drill cuttings. Outside of Cook Inlet, this option uses a combination of grinding and injection and onshore disposal as a basis for complying with zero discharge of drilling fluids and drill cuttings. a. Costs. Operators would not incur any costs under Option 1 because the requirements reflect current practice. Costs to comply with Option 2 (zero discharge all) are attributed only to Cook Inlet operators (North Slope operators are beneficially reusing a portion of their drill cuttings and all other coastal operators are already practicing zero discharge). Costs to comply with this option are estimated to be approximately $8,200,000 annually for the Cook Inlet operators. The basis for this cost analysis is that drilling fluids and drill cuttings generated in Cook Inlet would be hauled to shore for disposal. Costs for land disposal include water vessel transportation, storage prior to transport to the disposal facility, truck transportation to the disposal facility, and landfill disposal costs. While it was evaluated, grinding and injection is not used in the cost basis for Cook Inlet because, as mentioned earlier, geology amenable to grinding and injection does not appear to occur throughout Cook Inlet. To determine the volume of drilling wastes requiring disposal, EPA obtained the projected drilling schedules for the Cook Inlet operators using information from the 1993 Coastal Oil and Gas Questionnaire and contacts with industry. Using information about the volume of drilling fluids and drill cuttings generated per well, and the projected amount of drilling over the seven years following scheduled promulgation, EPA estimates that the total amount of drilling fluids and drill cuttings annually generated from these drilling operations will be approximately 89,000 barrels. EPA also considered the logistical difficulties of transporting drilling wastes in Cook Inlet as part of EPA's costing analysis of the options. To achieve zero discharge, platforms would transport drilling wastes to the eastern side of Cook Inlet by supply boat, then: (1) Transfer the wastes to barges for transport to an existing landfill facility on the west side of the Inlet or (2) load these wastes onto trucks for transport to landfill disposal in Oregon. During periods of extensive ice floes, the drilling wastes are stored on the east side of the Inlet for extended periods of time. For new sources, EPA expects that the costs of complying with NSPS would be equal to or less than those for existing sources. Note that, due to the high cost of installing new sources and the low expectation of return, EPA does not expect new sources to be installed in Cook Inlet independent of any new environmental regulations. EPA also analyzed non-water quality environmental impacts for BAT and NSPS. These impacts are discussed in Section IX of the preamble. b. BAT and NSPS Option Selection. For both BAT and NSPS control of drilling fluids, drill cuttings and dewatering effluent, EPA is establishing zero discharge limitations, except for Cook Inlet. In Cook Inlet, discharge limitations include no discharge of free oil, no discharge of diesel oil, both 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000 ppm SPP. BAT limitations for dewatering effluent are applicable prospectively. BAT limitations in this rule are not applicable to discharges of dewatering effluent from reserve pits which as of the effective date of this rule no longer receive drilling fluids and drill cuttings. Limitations on such discharges shall be determined by the NPDES permit issuing authority. With regard to coastal facilities outside of Cook Inlet, zero discharge is technically and economically achievable and has acceptable non-water quality environmental impacts because it reflects current industry practices under existing permit requirements. With regard to coastal facilities in Cook Inlet, EPA rejected zero discharge in large part because the technology of grinding and injection has not been demonstrated to be available throughout Cook Inlet. Drilling fluids and drill cuttings cannot be injected into producing formations, as is sometimes the case for produced water, because [[Page 66096]] they would interfere with hydrocarbon recovery. Thus, operators must have available different formation zones with appropriate characteristics (e.g., porosity and permeability) for injection of drilling fluids and drill cuttings. See the Coastal Development Document for discussion of geologic characteristics for the injection of these drilling wastes. Unlike the coastal region along the Gulf of Mexico or the North Slope of Alaska, where the subsurface geology is relatively porous and formations for injection are readily available, the geology in Cook Inlet is highly fragmented and information in the record indicates that formations for injection may be not available throughout Cook Inlet. EPA reviewed information where attempts to grind and inject drilling fluids and drill cuttings failed in the Cook Inlet area. For example, one operator attempted to operate a grinding and injection well in the Kenai gas field failed due to downhole mechanical failure of the injection well (1992/1993). There, the well experienced abnormal pressure on the well annulus, necessitating shutdown of the disposal operation. The operator also attempted annular pumping of drilling fluids and drill cuttings in two production wells in the Ivan River Field (onshore on the west side of Cook Inlet) where the annuli of both wells plugged during injection. Another operator, attempting to pump drilling waste into the annuli of exploration wells, lost the integrity of the well. Because not all of the drilling fluids and drill cuttings can be injected, much of the waste would have to be land disposed. All but two of the operators would likely have to transport their drilling fluids and drill cuttings to a disposal facility out of state; the two other operators privately own the only drilling waste land disposal facility near Cook Inlet. (EPA is unaware of any other onshore disposal facilities coming into existence, as Cook Inlet is a fairly mature field nearing the end of its useful life. All but one of the existing platforms were installed in the 1960s. The newest platform began production in 1987, but production from the facility has remained well below expectations.) Land disposal is a problem for Cook Inlet operators, analogous to those faced by offshore operators in Alaska, because the climate and safety conditions that exist during parts of the year in Cook Inlet make transportation of drilling fluids and drill cuttings particularly difficult and hazardous. The harsh climate, snow, ice, and poor visibility from fog and snow often restrict land and sea transportation. Also, the extensive tidal fluctuations (frequently in excess of 30 feet), strong currents, and ice formation during winter months in the Inlet impose severe logistical difficulties for storing and transporting the drilling wastes. Moreover, the limited storage space on platforms and transportation-related difficulties and delays associated with a zero discharge limitation for all drilling wastes would impose severe operational constraints on drilling activities. Thus, for purposes for BAT and NSPS, EPA does not believe that land disposal of all drilling wastes is generally available for Cook Inlet operators. There are non-water quality environmental impacts associated with such transportation and land disposal. For BAT, EPA estimates that zero discharge would result in 5,200 Barrel of Oil Equivalents (BOE) of fuel being used annually, resulting in 36 tons or 72,000 pounds of air emissions to move the waste from Cook Inlet to Oregon and sites near Cook Inlet. While EPA believes the non-water quality environmental impacts--in and of themselves--are not unacceptable, by comparison with the operational constraints discussed above and pollutants removed by zero discharge, 4,300 pounds of toxic pollutants annually, these non- water quality environmental impacts weigh against requiring zero discharge in Cook Inlet. Again, for NSPS control of drilling fluids, drill cuttings, and dewatering effluent, EPA is establishing zero discharge limitations, except for Cook Inlet. In Cook Inlet, discharge limitations include no discharge of free oil, no discharge of diesel oil, both 1 mg/kg mercury and 3 mg/kg cadmium limitations on the stock barite, and a toxicity limitation of 30,000 ppm SPP. Both inside and outside of Cook Inlet, these NSPS limitations are technically and economically achievable and has acceptable non-water quality environmental impacts because they reflect current practice. With regard to the potential for a barrier to entry, NSPS are equal to BAT limitations. BAT limitations have been demonstrated to be economically achievable for existing structures. Design and construction of pollution control equipment on new production facilities is generally less expensive than retrofitting existing facilities. Therefore, while the NSPS are equal to BAT limitations, it is less costly for new structures to meet these requirements and these costs would not inhibit development of new sources. 5. BCT a. BCT Cost Test Methodology. EPA establishes BCT limitations based on a methodology which became effective August 22, 1986 (51 FR 24974, July 9, 1986). This methodology compares the costs of conventional pollutant removal under BCT with the cost of conventional pollutant removal at a publicly owned treatment works (POTW). A description of this methodology is contained in the preamble to the proposed rule (60 FR 9428, 9444) and the Coastal Development Document. If all options fail either of the two tests, then BCT limitations must be set at a level equal to BPT limitations. b. BCT Costs Test Calculations and Options Selection. (i) Coastal Subcategory Except for Cook Inlet. Because all operators throughout the coastal subcategory, except in Cook Inlet, are currently practicing zero discharge of drilling fluids and drill cuttings and dewatering effluent, zero discharge was the only option considered. There is zero cost for this limitation. Thus, EPA determined that zero discharge passes the BCT cost tests and is the appropriate BCT limitation for this wastestream. BCT limitations for dewatering effluent are applicable prospectively. BCT limitations in this rule are not applicable to discharges of dewatering effluent from reserve pits which as of the effective date of this rule no longer receive drilling fluids and drill cuttings. Limitations on such discharges shall be determined by the NPDES permit issuing authority. (ii) Cook Inlet. EPA considered two BCT options for Cook Inlet: BPT limitations (no free oil) or zero discharge. BCT limits in the final rule are established equal to BPT. Although zero discharge was determined to be not available in Cook Inlet, the BCT cost test was calculated to show whether such a limitation would have passed the cost test. EPA determined that zero discharge limitations would not have passed the BCT cost test. Costs, pollutant reductions, and the results of the BCT cost test are presented in detail in the Coastal Development Document. BCT limitations for dewatering effluent are applicable prospectively. BCT limitations in this rule are not applicable to discharges of dewatering effluent from reserve pits which as of the effective date of this rule no longer receive drilling fluids and drill cuttings. Limitations on such discharges shall be determined by the NPDES permit issuing authority. [[Page 66097]] 6. PSES and PSNS Section 307 of the CWA authorizes EPA to develop pretreatment standards for existing sources (PSES) and new sources (PSNS). Pretreatment standards are designed to prevent the discharge of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of POTWs. The pretreatment standards for existing sources are to be technology based and analogous to the best available technology economically achievable (BAT) for direct dischargers. The pretreatment standards for new sources are to be technology-based and analogous to the best available demonstrated control technology used to determine NSPS for direct dischargers. New indirect discharging facilities, like new direct discharging facilities, have the opportunity to incorporate the best available demonstrated technologies, including process changes, and in-plant controls, and end-of-pipe treatment technologies. EPA determines which pollutants to regulate in PSES and PSNS on the basis of whether or not they pass through, interfere with, or are incompatible with the operation of POTWs. Based on comments, the 1993 Coastal Oil and Gas Questionnaire, and other information reviewed as part of this rulemaking, EPA has not identified any existing coastal oil and gas facilities which discharge drilling fluids, drill cuttings, or dewatering effluent to POTW's, nor are any new facilities projected to direct these wastes in such manner. However, due to the high solids content of drilling fluids and drill cuttings, EPA is establishing pretreatment standards for existing and new sources equal to zero discharge because these wastes would interfere with POTW operations. For further discussion, see the Coastal Development Document. For PSNS, zero discharge would not cause a barrier to entry, as further discussed in the Economic Impact Analysis. B. Produced Water and Treatment, Workover, and Completion Fluids At proposal, produced water was discussed and analyzed separately from treatment, workover, and completion fluids (TWC). However, EPA also proposed that discharge limitations for TWC be set equal to discharge limitations for produced water. As stated at that time, based on responses to the 1993 Coastal Oil and Gas Questionnaire and EPA's Region 10 Discharge Monitoring Reports, the typical industry practice is to combine produced water with treatment, workover, and completion fluids for purposes of wastewater treatment. Because the treatment technologies for these wastestreams are linked, EPA has combined these wastestreams in the final rule for purposes of discussion. 1. Waste Characterization Produced water is brought to the surface during the oil and gas extraction process and can include: formation water extracted along with oil and gas; injection water used for secondary oil recovery that has broken through the formation and mixed with the extracted hydrocarbons; and various well treatment chemicals added during the production and oil/water separation processes. Produced water is the highest volume waste in the coastal oil and gas industry. Depending on the age of a well and site-specific formation characteristics, the produced water can constitute between 2 percent and 98 percent of the gross fluid production at a particular well. Generally, in the early production phase of a well the produced water volume is relatively small and the hydrocarbon production makes up the bulk of the fluid. Over time, the formation approaches hydrocarbon depletion and the produced water volume usually exceeds the hydrocarbon production. Based on information received in the 1993 Coastal Oil and Gas Questionnaire, the average produced water rate from a well is approximately 1180 barrels per day (bpd) in Cook Inlet and 270 bpd in the Gulf Coast. EPA estimates under current permit requirements that 119 million barrels per year (bpy) of produced water are discharged to surface waters by the coastal oil and gas industry. As part of this rulemaking, EPA has embarked upon a systematic effluent sampling program to identify and quantify the pollutants present in produced water, with an emphasis toward the identification of listed toxic pollutants. Details of EPA's data collection activities are presented in the Coastal Development Document. The information collected has confirmed the presence of a number of organic and metal toxic pollutants in produced water. Pollutants contained in produced water discharges from facilities in the coastal oil and gas industry with treatment systems able to meet BPT permit limits were identified as part of EPA's sampling effort. A summary of the data from these sampling activities is contained in the Coastal Development Document. EPA's sampling data and the industry- supplied Cook Inlet Study identified many organic toxic pollutants and 12 of the 13 metal toxic pollutants as being present in BPT treated discharges of produced water following some treatment for oil and grease (oil) removal. The toxic organics most often present in significant amounts were benzene, naphthalene, phenol, toluene, and ethylbenzene. In addition to the toxic pollutants, EPA identified total suspended solids, oil and grease, and a number of nonconventional pollutants including barium, chlorides, ammonia, magnesium, strontium and iron present in produced water. TWC fluids are primarily generated during production. Well treatment and workover fluids are inserted downhole in a producing well to increase a well's productivity or to allow safe maintenance of the well. Completion fluids are inserted downhole after a well has been drilled, and serve to clean the wellbore and maintain pressure prior to production. In most operations, these fluids resurface with the production fluids once production is initiated and can be reused, discharged, or injected in a disposal well. According to results obtained in the 1993 Coastal Oil and Gas Questionnaire, EPA estimates that approximately 275,000 bbls (205,000 and 70,000 bpy of treatment/workover and completion fluids respectively) of TWC fluids are discharged annually from coastal oil and gas operations in Texas and Louisiana under current permit requirements. The composition of the discharges is highly dependent on the fluid's purpose, but they generally consist of acids (in the case of treatment) or weighted brines (for workover of completion). The principal pollutant in these fluids is oil and grease ranging in concentration from 15 to 722 mg/l. Total suspended solids, another major constituent in these fluids, is present in concentrations ranging from 65 to 1600 mg/l. Prominent toxic metals that exist in these wastes include chromium, copper, lead, and zinc. Priority organics are also present including acetone, benzene, ethylbenzene, xylene, toluene, and naphthalene. Under current permit requirements, EPA estimates that approximately 314,000 pounds of priority pollutants and 3,700,000 pounds of conventional pollutants are being discharged annually into the coastal subcategory. In addition, approximately 2.55 million pounds of nonconventionals are being discharged including boron, calcium, cobalt, iron, manganese, molybdenum, tin, vanadium, and yttrium. 2. Selection of Pollutant Parameters a. Pollutants Regulated. Where zero discharge is required, all pollutants [[Page 66098]] found in produced water and treatment, workover, and completion fluid discharges are controlled. Where discharges are allowed, i.e., Cook Inlet, EPA is regulating oil and grease under BAT as an indicator pollutant controlling the discharge of toxic and nonconventional pollutants. Operationally, oil and grease is measured by EPA's method for Total Oil and Grease. Oil and grease is limited for produced water under BCT as a conventional pollutant. BCT limits for treatment, workover, and completion fluids prohibit the discharge of ``free oil'' as a surrogate for control over the conventional pollutant ``oil and grease.'' No discharge of ``free oil'' is determined by the static sheen test. EPA is prohibiting discharge of ``free oil'' as a surrogate for control over the conventional pollutant ``oil and grease'' in recognition of the complex nature of the oils present in drilling fluids, including crude oil from the formation being drilled. Oil and grease is limited under NSPS as both a conventional pollutant and as an indicator pollutant controlling the discharge of toxic and nonconventional pollutants. It has been shown (see the Coastal Development Document) that oil and grease serves as an indicator for toxic pollutants in the produced water wastestream, including phenol, naphthalene, ethylbenzene, and toluene. During its development of the Offshore Guidelines, EPA showed that gas flotation technology (the technology basis for the oil and grease limitations) removes both metals and organic compounds, resulting in lower concentration levels in the discharge for the above toxic pollutants (see Section IX of the Offshore Development Document). b. Pollutants Not Regulated. For Cook Inlet, EPA evaluated the feasibility of regulating separately each of the constituents present in produced water and treatment, workover, and completion fluids during the development of the Offshore Guidelines. Based on that analysis, EPA determined for the Coastal Guidelines that it is not feasible to regulate each pollutant individually for reasons that include the following: (1) The variable nature of the number of constituents in the produced water and treatment, workover, and completion fluids, (2) the impracticality of measuring a large number of analytes, many of them at or just above trace levels, (3) use of technologies for removal of oil which are effective in removing many of the specific pollutants, and (4) many of the organic pollutants are directly associated with oil and grease because they are constituents of oil, and thus, are directly controlled by the oil and grease limitation. See the Coastal Development Document for more details. 3. Control and Treatment Technologies a. Current Practice. With regards to produced water, information collected by EPA through the 1993 Coastal Oil and Gas Questionnaire as well as industry contacts indicate that no coastal oil and gas facilities are discharging in Alabama, Alaska's North Slope, California, Florida, or Mississippi. This is due to a combination of factors including operational preference, waterflooding, and/or state and federal requirements. The Louisiana Department of Environmental Quality issued regulations in 1992 (LAC:33, IX, 7.708) which prohibit discharges of produced water to fresh water areas characterized as ``upland'' after July 1, 1992. The Louisiana regulation defines ``upland'' as ``any land not normally inundated with water and that would not, under normal circumstances, be characterized as swamp of fresh, intermediate, brackish or saline marsh''. The regulation does, however, allow discharges of produced water to a major deltaic pass of the Mississippi River or to the Atchafalaya River below Morgan City. The same regulation also requires that discharges inland of the inner boundary of the Territorial Seas into intermediate, brackish or saline waters must either cease discharges or comply with a specific set of effluent limitations. These requirements must be met within a certain time frame, as required in the regulations, but, no later than January 1997. In addition, EPA issued general NPDES permits (60 FR 2387, January 9, 1995) for production wastes that prohibit discharges of produced water in coastal areas of Texas and Louisiana. The permits do not, however, apply to produced water derived from the offshore subcategory which is discharged into a main pass of the Mississippi River or Atchafalaya River below Morgan City. Along with the general permits, EPA issued an Administrative Order allowing until January 1997 to comply with the zero discharge requirement. Thus, although many coastal oil and gas operators are currently discharging produced water, current permit requirements and administrative orders indicate that the only facilities projected to be discharging by January 1997 would be those in Cook Inlet, Alaska, and six facilities discharging to a major deltaic pass of the Mississippi River. Subsequent to EPA's issuance of the final coastal production permits, 82 facilities (as of the date of this writing) in Texas have applied to EPA Region 6 for individual NPDES permits authorizing discharge of produced water. Additionally, the U.S. Department of Energy has provided the State of Louisiana with comments and analyses suggesting a change in the Louisiana state law requiring zero discharge of produced water to open bays by January 1997. The current BPT regulations established for the coastal subcategory limit the oil and grease content in the discharged produced water. Existing technologies for the removal of oil and grease include gravity separation, gas flotation, heat and/or chemical addition to assist oil- water separation, and filtration. Methods for the discharge or disposal of produced water from facilities in the coastal subcategory include free fall discharge to surface waters, discharge below the water surface, use of channels to convey the discharge to water bodies, and injection via regulated Class II Underground Injection Control (UIC) wells into underground formations. As an alternative, a number of production sites transport produced water by pipeline, truck or barge to shore facilities for disposal in UIC Class II wells. At times, this transport consists of the gross fluid produced and the oil-water separation takes place at the off-site facility. While sampling data has indicated quantifiable reductions of naphthalene, lead, and ethylbenzene by BPT treatment (i.e., by oil- water separation technology), this data also demonstrates the presence of significant levels of toxic pollutants remaining in the treated effluent. With regard to treatment, workover, and completion fluids, current requirements for the control of discharges from these fluids include BPT limitations prohibiting free oil. EPA's final general permits applicable to discharges from coastal oil and gas drilling operations in Texas and Louisiana further prohibit discharges of treatment, workover and completion fluids to freshwater areas. Methods for treatment and discharge or disposal include: * Treatment and disposal along with the produced water * Neutralization for pH control and discharge to surface waters * Onshore disposal and/or treatment and discharge in coastal or offshore areas. In addition, these fluids may in some cases be reused. b. Additional Technologies. [[Page 66099]] In developing the regulation, EPA evaluated several treatment technologies for application to the produced water and treatment, workover, and completion fluid wastestreams. These technologies were considered for implementation at the coastal production sites and at the shore facilities where much of the produced water is currently treated for subsequent discharge to coastal subcategory waters. (1) Improved Gas Flotation. Gas flotation is a treatment process that separates low-density solids and/or liquid particles (e.g., oil and grease) from liquid (e.g., water) by introducing small gas (usually air) bubbles into wastewater. As minute gas bubbles are released into the wastewater, suspended solids or liquid particles are captured by these bubbles, causing them to rise to the surface where they are skimmed off. EPA considered as an option using gas flotation technology with chemical addition as a basis for improving BPT-level performance. This option would require all coastal discharges of produced water to comply with oil and grease limitations of 29 mg/l monthly average and a daily maximum of 42 mg/l. The technology basis for these limitations is improved operating performance of gas flotation technology. EPA has determined that gas flotation systems could be improved to increase removal efficiencies--i.e., the amount of pollutants removed. Specific mechanisms include proper sizing of the gas flotation unit to improve hydraulic loading (water flow rate through the equipment), adjustment and closer monitoring of engineering parameters such as recycle rate and shear forces that can affect oil droplet size (the smaller the oil droplet, the more difficult the removal), additional maintenance of process equipment, and the addition of chemicals to the gas flotation unit. (See Offshore Development Document Section IX.) The addition of chemicals can be a particularly effective means of increasing the amount of pollutants removed. Because the performance of gas flotation is highly dependent on ``bubble-particle interaction,'' chemicals that enhance that interaction will increase pollutant removal. Gas flotation is a technology which has been used for many years in treating produced water. This technology formed the basis for the BPT regulations EPA promulgated in 1979. In developing final effluent limitations guidelines and standards for the offshore subcategory (58 FR 12454; March 4, 1993), EPA evaluated comments and data submitted by the industry which strongly urged EPA to select improved gas flotation technology as the basis for BAT limits and NSPS, based on data presented by the Offshore Operators Committee's (OOC's) 83 Platform Composite Study. Industry further noted that chemical additives would improve the amount of oil and grease in produced water that could be removed. EPA thoroughly reviewed these comments and additional data, and agreed with industry that improved gas flotation was the appropriate technology for setting BAT limits and NSPS in the offshore subcategory. In establishing BAT limits and NSPS for produced water in the Offshore Subcategory, EPA evaluated the effluent data from the platforms in the 83 Platform Composite Study identified as using improved gas flotation (e.g., use of gravity separators and chemical additives). First, EPA modeled the offshore platform with ``median'' oil and grease effluent values--i.e., 50 percent of the platforms in the database had oil and grease effluent values above (and 50 percent below) the median of the effluent values measured at the median platform. Based on the oil and grease measured at the median platform after improved gas flotation treatment, and allowing for average ``within-platform'' variability, EPA set a daily maximum limit on oil and grease at 42 mg/l, and a 30-day average of 29 mg/l as the BAT limits and NSPS. (See 58 FR 12462, March 4, 1993.) Since there are fewer operational constraints for coastal facilities than there are for offshore facilities, the BAT and NSPS limitations developed for the offshore subcategory, based on improved gas flotation technology, are technologically achievable in the coastal subcategory. (2) Injection. EPA also considered using injection technology as a basis for setting a zero discharge requirement under this rule. With the exception of Cook Inlet, injection of produced water is widely practiced by facilities in the coastal subcategory. Independent of this rule, all coastal facilities in Alabama, California, Florida, and the North Slope of Alaska are currently practicing zero discharge and, as of January 1, 1997, EPA estimates that at least 80% to 99.9% of all coastal facilities in Louisiana and Texas will be practicing zero discharge. The 80% estimate is based on subtracting the sum of the 6 facilities discharging into a major deltic pass of the Mississippi, the 82 facilities discharging to Louisiana open bays, and the 82 facilities associated with individual permit applicants in Texas from the 853 total coastal facilities estimated to exist along the Gulf of Mexico. The 99.9% estimate is based on subtracting the number of facilities discharging into a major deltic pass of the Mississippi from the total number coastal facilities along the Gulf of Mexico. Additionally, using a combination of Coastal Survey information and counts of facilities known to be discharging, EPA estimated that 62% of coastal facilities along the Gulf of Mexico were practicing zero discharge in 1994. For the onshore subcategory, injection is the predominant technology used to comply with the zero discharge 1979 BPT limitation. Injection technology for produced water consists of injecting produced water, under pressure, into Class II UIC wells into underground formations. This option results in no discharge of produced water to surface waters. 4. Other Technologies Other technologies considered but rejected are discussed in the Coastal Development Document. 5. Options Considered EPA considered several options in developing BCT, BAT, NSPS, PSES and PSNS limitations for discharges of produced water and treatment, workover, and completion fluids by coastal facilities or in coastal locations. The bases for these options were gas flotation, improved gas flotation, injection, or a combination of injection and improved gas flotation. As proposed, implementation of limitations on discharges of offshore wastes into the coastal subcategory is accomplished by the addition of language describing the applicability of subcategory limitations when crossing subcategory boundaries and modification of the applicability language for the offshore subcategory. Limitations for the Agricultural and Wildlife Water Use Subcategory and the reserved status of the Stripper Subcategory are not affected by changes in the applicability language. The three options selected for final consideration in developing BAT and NSPS for control of produced water are listed below with limitations associated with the options allowing discharges: Option 1--(Zero Discharge; Except Major Deltaic Pass and Cook Inlet Based On Improved Gas Flotation): With the exception of facilities in Cook Inlet and facilities discharging offshore produced water into the coastal subcategory waters of a major deltaic pass of the Mississippi River or the Atchafalaya River below Morgan City, all coastal oil and gas facilities and all facilities discharging offshore produced water into coastal locations would be prohibited from discharging produced water and treatment, workover, and completion fluids. Coastal facilities in Cook Inlet and facilities [[Page 66100]] discharging offshore produced water into a major deltaic pass would be required to comply with oil and grease limitations of 29 mg/l monthly average and 42 mg/l daily maximum based on improved performance of gas flotation. Option 2--(Zero Discharge; Except Cook Inlet Based On Improved Gas Flotation): With the exception of coastal facilities in Cook Inlet, all coastal oil and gas facilities would be prohibited from discharging produced water and treatment, workover, and completion fluids. Discharges of offshore produced water and treatment, workover, and completion fluids would be prohibited when the wastes are disposed in coastal locations. Coastal facilities in Cook Inlet would be required to comply with oil and grease limitations of 29 mg/l monthly average and 42 mg/l daily maximum based on improved performance of gas flotation. Option 3--(Zero Discharge All): For all coastal facilities, this option would prohibit discharges of produced water and treatment, workover, and completion fluids based on injection. Further, discharges of offshore produced water and treatment, workover, and completion fluids would be prohibited in coastal locations. For BCT, BPT and currently applicable permit limitations were considered in addition to the three previously mentioned options for BAT and NSPS. For produced water, BPT limitations include limitations on oil and grease of 48 mg/l for Monthly Average and 72 mg/l for Daily Maximum. For treatment, workover, and completion fluids, BPT limitations include no discharge of free oil and current permits, where applicable, prohibit the discharge of these fluids into fresh waters of Texas and Louisiana. For PSES and PSNS, the only option considered is zero discharge. With regard to options presented at proposal: (1) Options for treatment, workover, and completion fluids have been incorporated into the options for produced water and (2) one option was added. The option that considers allowing the discharge of offshore produced water into a major deltaic pass of the Mississippi River was included in response to comments. In response to comments, specific alternatives have been developed and examined carefully for facilities currently discharging offshore produced water into a major deltaic pass of the Mississippi River or the Atchafalaya River below Morgan City. EPA has identified six facilities with eight outfalls discharging offshore produced water into a major deltaic pass of the Mississippi River and no facilities discharging offshore produced water into the Atchafalaya River below Morgan City. The specific alternatives discussed above have been developed for Cook Inlet to account for the different operational practices, geological situations, and economic considerations that exist in Cook Inlet. 4. BAT and NSPS Options EPA is selecting ``Option 2--Zero discharge; Except Cook Inlet Based On Improved Gas Flotation'' for the BAT and NSPS level of control for produced water. a. Rationale for Selection of BAT (1) Coastal Subcategory (except Cook Inlet) EPA is establishing zero discharge as BAT for the coastal subcategory (except for Cook Inlet) because it is technically available, economically achievable and reflects the appropriate level of BAT control. Zero discharge of produced water is technically available. Zero Discharge of produced water has been required of onshore facilities since EPA promulgated BPT regulations for the onshore subcategory of the oil and gas industry in 1979. 40 CFR part 435, subpart C (44 FR 22069; April 13, 1979). With the exception of Cook Inlet, injection of produced water is widely practiced by facilities in the coastal subcategory. Independent of this rule, all coastal facilities in Alabama, California, Florida, and the North Slope of Alaska are currently practicing zero discharge and, as of January 1, 1997, EPA estimates that at least 80% to 99.9% of all coastal facilities in Louisiana and Texas will be practicing zero discharge. The 80% estimate is based on subtracting the sum of the 6 facilities discharging into a major deltic pass of the Mississippi, the 82 facilities discharging to Louisiana open bays, and the 82 facilities associated with individual permit applicants in Texas from the 853 total coastal facilities estimated to exist along the Gulf of Mexico. The 99.9% estimate is based on subtracting the number of facilities discharging into a major deltic pass of the Mississippi from the total number of coastal facilities along the Gulf of Mexico. Additionally, using a combination of Coastal Survey information and counts of facilities known to be discharging, EPA estimated that 62% of coastal facilities along the Gulf of Mexico were practicing zero discharge in 1994. Some coastal operators have voluntarily upgraded to zero discharge technologies while other coastal operators have been subject to consent decrees requiring zero discharge in citizen suits filed by environmental groups. Zero discharge is available to coastal facilities in the Gulf of Mexico region because formations appropriate for injection are available. In response to comments that operators discharging offshore produced water into a major deltaic pass of the Mississippi should not be subject to zero discharge, EPA closely examined these facilities. However, EPA has identified no basis for providing these facilities with limitations other than those established for the coastal subcategory outside of Cook Inlet. Injection has been widely demonstrated in practice as available to coastal facilities in states along the Gulf Coast, including facilities discharging coastal produced water that are near these facilities discharging offshore produced water. Zero discharge for the coastal subcategory, except Cook Inlet, is economically achievable. As discussed below, EPA conducted the economic analysis under two baselines, the current regulatory requirements baseline and an alternative baseline. Under the current requirements baseline, the only facilities outside of Cook Inlet that are incurring costs as a result of this rule are those discharging wastes from the offshore subcategory into a ``major deltaic pass.'' Under the alternative baseline, facilities outside of Cook Inlet that are incurring costs as a result of this rule includes those discharging wastes from the offshore subcategory into a ``major deltaic pass,'' individual permit applicants in Texas, and Louisiana open bay dischargers. No closures are projected for the six facilities discharging to a major deltaic pass. Major pass facilities incur costs and impacts under both the current requirements and the alternative baselines. For major pass operations, the lifetime production loss is expected to be up to 3.4 million total BOE, which is 0.6 percent of estimated lifetime production from these facilities. While these losses may be significant for these dischargers, in context of the coastal subcategory as a whole, this production loss represents 0.3 percent of the coastal production along the Gulf of Mexico. Employment losses in both Cook Inlet and along the Gulf Coast are acceptable, see section VIII. Considering this small percentage loss of BOE and profitability, coupled with the determination of no closures, EPA believes that zero discharge is economically achievable under the CWA. For individual permit applicants in Texas and Louisiana open bay dischargers, a total of up to 94 wells may be first year shut-ins under zero discharge. Individual permit applicants in Texas and Louisiana open bay dischargers are considered to have financial impacts only under the alternative baseline. These wells are [[Page 66101]] approximately 2 percent of all Gulf of Mexico coastal wells. EPA estimates related production losses would be approximately 12.8 million BOE. This represents less than one percent of all Gulf coastal production, most of which is in compliance with zero discharge requirements. A maximum of 1 firm among the Louisiana open bay dischargers and 3 firms among the individual permit applicants from Texas could fail as a result of the proposed regulatory options. However, EPA's modeling tends to overestimate economic impacts and firm failures, since these models project that some currently operating firms have already failed. These potential failures represent less than one percent of all Gulf of Mexico coastal firms. EPA also did a facility level analysis, conducted in response to facility-level information received from Texas very late in the rulemaking, that shows fewer wells are baseline failures and fewer wells fail due to the costs of this rule because wells combine efforts for treatment and production. EPA views the small percentage loss of BOE and profitability, coupled with the determination of a small number of firm closures, to meet the definition of economic achievability under the CWA. The non-water quality environmental impacts of zero discharge, discussed in section IX, are acceptable. (2) Cook Inlet EPA is establishing BAT limitations based on improved gas flotation, rather than zero discharge. EPA rejects zero discharge of produced water because zero discharge is not economically achievable in Cook Inlet. EPA considered Cook Inlet separately from other areas in the coastal subcategory because Cook Inlet is geographically isolated from other areas in the coastal subcategory, zero discharge of produced water would have disproportionately adverse economic impact in Cook Inlet. Unlike states along the Gulf Coast, only the production formation is generally available for injection of produced water. Because of this, zero discharge would require the additional costs associated with piping produced water from existing production facilities to existing waterflood injection sites. EPA's economic analysis shows a disproportionate impact of zero discharge on Cook Inlet as compared with the rest of the coastal subcategory. EPA projects that zero discharge requirements for Cook Inlet would close 1 of the 13 existing production platforms and result in the loss of 108 jobs in the oil and gas industry in Cook Inlet. In addition, there are severe economic impacts on two additional platforms that were projected to fail at proposal. These disproportionate impacts are demonstrated by a loss in net present value in Cook Inlet of 18.5 percent as compared to only 1.4 percent in the Gulf coast under the current requirements baseline. In addition, there are disproportionate impacts in Cook Inlet with regard to employment, where Cook Inlet already suffers from unemployment higher than the national average and higher than the rest of the coastal subcategory. The most recently reported (1991) unemployment rate in Cook Inlet is 12.7 percent, as compared with the unemployment rate in the Gulf coast of 6.2 to 6.4 percent and the national unemployment rate of about 5.2 percent). The loss of 108 jobs that would occur in Cook Inlet from zero discharge would raise the unemployment level in Cook Inlet 0.5 percent, to 13.2 percent. Thus, zero discharge would worsen the serious unemployment situation that exists in Cook Inlet. Because Cook Inlet is economically and geographically isolated and the economic effects of zero discharge in Cook Inlet are significant and disproportionately worse than they are in the rest of the subcategory, EPA rejects zero discharge in Cook Inlet as not economically achievable. Limitations based on improved gas flotation are technically and economically achievable for Cook Inlet facilities. These limitations are a Daily Maximum of 42 mg/l and a Monthly Average of 29 mg/l for oil and grease. Improved gas flotation technology has been demonstrated in the offshore subcategory where the wastestreams and physical constraints are similar. No platform closures are expected as a result of establishing these limitations. EPA expects the production loss over the productive lifetime of these platforms to be approximately 2.4 million BOE, which is 0.5 percent of the estimated lifetime production for the Inlet. The non-water quality environmental impacts of these limitations, discussed in section IX, are acceptable. (3) Pollutant Reductions for the Selected Option Assuming the current regulatory requirements baseline, the selected BAT option for produced water and treatment, workover, and completion fluids is expected to reduce discharges of conventional pollutants by 2,780,000 lbs. per year, nonconventional pollutants by 1,490,000,000 lbs. per year, and toxic pollutants by 228,000 lbs. per year. Assuming the alternative baseline, the selected BAT option for produced water and treatment, workover, and completion fluids is expected to reduce discharges of conventional pollutants by 11,300,000 lbs. per year, nonconventional pollutants by 4,590,000,000 lbs. per year, and toxic pollutants by 880,000 lbs. per year. b. Rationale for Selection of NSPS For NSPS control of produced water and treatment, workover, and completion fluid discharges from new sources, EPA is establishing the limitations associated with ``Option 2--Zero Discharge; Except Cook Inlet Based On Improved Gas Flotation.'' Option 2 is economically achievable for the reasons discussed in the economic impact analysis and in Section VIII, below. The selected option for NSPS is equal to the selected BAT option for produced water and treatment, workover, and completion fluids. The BAT option has been demonstrated to be technologically available and economically achievable for existing structures. Design and construction of pollution control equipment on new production facilities is generally less expensive than retrofitting existing facilities. Therefore, while the NSPS requirements are equal to the BAT requirement, it is less costly for new structures to meet these requirements and these costs would not inhibit development of new sources. In addition, as discussed in Section IX, EPA has determined the non-water quality environmental impacts to be acceptable for the selected NSPS option for produced water and treatment, workover, and completion fluids. Zero discharge for Cook Inlet is rejected because of uncertainties regarding the availability of geologic formations suitable for receiving injected produced water. Information in the record indicates that a potential new source in Cook Inlet could be unable to inject adequate produced water volumes near the new source. As a result, the new source would be faced with piping the produced water to a location where suitable geology would be available. Based on information available in the record, EPA projects that no new sources will be developed in Cook Inlet. Nevertheless, EPA assessed the costs and economic impacts incurred by a model new source facility under the zero discharge scenario should conditions and future information lead to development of new sources in Cook Inlet. For the modeled scenario, EPA based costs on injecting produced water near the new source facility. However, because of the uncertainties regarding availability of formations suitable for injection, it is possible that a new source structure would incur some [[Page 66102]] unknown cost for piping the produced water to a suitable injection location. Since the location and availability of formations for any new source in Cook Inlet are unknown, the maximum cost associated with piping produced water from the wellhead to the nearest injection well cannot be estimated. 5. BCT Methodology and Options Selection The methodology to determine the appropriate technology option for BCT limitations is previously described in the proposal and the Coastal Development Document. EPA evaluated the options listed in section VII.B.5 according to the BCT cost reasonableness tests. The pollutant parameters used in this analysis were total suspended solids and oil and grease. All options fail the BCT cost reasonableness test. Thus, EPA establishes BCT limitations for produced water equal to BPT. Limitations for treatment, workover, and completion fluids are established as zero discharge for fresh water in Texas and Louisiana and no free oil everywhere else. This option reflects current permit requirements. Costs for this option are zero, thus this option passes the BCT cost test. A more detailed description of the BCT cost test for produced water and treatment, workover, and completion fluids is described in the Coastal Development Document. There are no non-water quality environmental impacts associated with the BCT limitations because it is equal to existing BPT requirements. 6. PSES and PSNS Options Selection Based on the 1993 Coastal Oil and Gas Questionnaire and other information reviewed as part of this rulemaking, EPA has not identified any existing coastal oil and gas facilities which discharge produced water or treatment, workover, and completion fluids to POTWs, nor are any new facilities projected to direct their produced water discharge in such manner. However, because EPA is establishing a limitation requiring zero discharge for existing facilities, there is the potential that some facilities may consider discharging to POTWs in order to circumvent the BAT and/or NSPS limitations. Pretreatment standards for produced water and treatment, workover, and completion fluids are appropriate because EPA has identified the presence of a number of toxic and nonconventional pollutants, many of which are incompatible with the biological removal processes at POTWs and would result in pass through or interference. Large concentrations of dissolved solids in the form of various salts in the produced water cause the discharge to POTWs to be incompatible with the biological treatment processes because these ``brines'' can be lethal to the organisms present in the POTW biological treatment systems. (See the Coastal Development Document for detailed information on produced water characterization.) EPA is establishing pretreatment standards for existing and new sources (PSES and PSNS, respectively) that prohibit the discharge of produced water and treatment, workover, and completion fluids. Since zero discharge to POTWs is the current practice in the coastal oil and gas extraction industry, zero discharge is economically and technologically achievable for PSES, and has no non-water quality environmental impacts. The cost projections for both PSES and PSNS are considered to be zero since no existing sources discharge to POTWs and there are no known plans for new sources to be installed in locations amenable to sewer hookup. Design and construction of pollution control equipment on new production facilities is generally less expensive than retrofitting existing facilities. Therefore, while the PSNS requirements are equal to the PSES requirement, it is less costly for new structures to meet these requirements and these costs would not inhibit development of new sources. Non-water quality environmental impacts would be similar to those for new sources, which EPA has found to be acceptab [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A96-28659. Public record. Not legal advice.